By Thomas M. Redlinger and John McCormick, Weatherford International

In 1950, the average depth of exploratory wells in the US was less than 4,700 ft and by 2000 the average well depth in the US reached a peak of nearly 7,000 ft. (Source: US Energy Information Association)

Drill pipe technical performance is rarely the starting point for well planning – engineers expect that drill pipe will handle the challenges, loads and environments that it encounters. Until recently, drill pipe has been able to keep ahead of drilling challenges. “Dumb iron,” as it is described in the industry, has evolved into a highly engineered drilling product, designed with features to reduce drilling fatigue, improve torsional and tensile strength, resolve slip crushing issues, and allow it to operate in sour drilling conditions.

Now, however, drill pipe features no longer far exceed the expectations of drilling programs. Without further improvements to materials, connections and fatigue life, the capabilities of the drill pipe could become the limiting factor in state-of-the-art drilling projects on the horizon.

Drilling operations today are considerably more complicated than they were 50 years ago. One significant change relates to the depth wells now regularly achieve. In 1950, the average depth of exploratory wells in the US was less than 4,700 ft. By 1990, the average depth was around 6,000 ft, and by 2000 the average well depth in the US reached a peak of nearly 7,000 ft. Furthermore, these wells are increasingly complex directional or horizontal wells.

Although the concept of drilling a horizontal well was developed as early as 1891, with Smalley Campbell’s patent on using a flexible shaft to rotate drill pipe, the first recorded truly horizontal well was not completed until 38 years later in Texas, and the regular practice of drilling horizontal and directional wells was not achieved until the early 1980s.

In the 1990s, less than 10% of the wells drilled were horizontal wells and horizontal wells now account for more than half of all drilling activity in the US. (Source: Baker Hughes International Rig count November 2010)

Horizontal drilling is commonplace. In the 1990s, less than 10% of the wells drilled were horizontal. Horizontal wells now account for more than half of all drilling activity in the US. At the same time, the complexity and difficulty of these wells is also being pushed, further challenging the limits of the drill stem.

The measured depth and departure of a horizontal well are often used as the variables to indicate total drilling complexity. From 2007 to 2010, the average measured depth of horizontal wells in the US increased from 10,000 ft to over 13,000 ft. The increase in horizontal departure is even more significant over a longer period of time.

A review of extended-reach drilling (ERD) from 1975 shows the extended-reach drilling record had a maximum departure-to-depth ratio of 2:1, barely achieving today’s definition of an extended-reach well. Today, the common definition of an extended-reach well is a well profile that has a step-out ratio above 2:1, although it has been suggested that the definition of extended-reach should focus on the departure relative to the equipment, total vertical depth and water depth.

Table 1: A review of drilling records by departure and total vertical depth indicates that there has only been a slight change in the departure record over the last five years and no change in the maximum TVD. (Source: K&M Technology)

The maximum ERD departure in 1975 was an absolute departure value of 10,900 ft (Table 1). The industry began regularly drilling these types of wells in the late 1980s and early 1990s. Today, the departure record is nearly four times the 1975 record, at 40,230 ft drilled by Maersk Oil. The departure-to-depth ratio is now over 10-to-1. Many technologies and products have been credited for the success of these drilling operations, including high-strength and high-torque drill pipe.

However, the industry’s ability to continue advancing the drilling of these extremely challenging wells has slowed in recent years. From 1975 to the mid-2000s, ERD record-holders frequently changed. In the last five years, however, there has been only a slight change in the departure record and no change in the maximum total vertical depth (TVD), as Table 1 indicates. Complex wells continue to be planned, but the equivalent circulating density (ECD) effects and torque and tensile limitations of the drill pipe often result in well designs that need to be modified to operate safely within the drill pipe ratings.

Dividing the standard industry drilling envelope by year, it can be seen how ERD may have begun to reach their technical limits (Figure 1). Each successive drilling record is taking much smaller steps from the previous record.

Figure 1: This industry drilling envelope plot from September 2009 illustrates that drilling operations today are considerably more complicated than they were in 1975. However, it also illustrates that each successive record is taking smaller steps from the previous record. Has extended-reach drilling begun to reach its technical limits? (Source: K&M Technology)

Although record-breaking wells are in a category of their own, today’s drillers regularly break the drilling records of the 1980s without significant planning.  The early 1980 definition of a “superdeep well” was drilling below 15,000 ft. Most of these 15,000-ft wells were vertical or near vertical in design. Today, wells with 15,000 ft measured depth are not uncommon.

Data from Spears show the 2010 average measured depth for directional and horizontal wells drilled in the US was over 13,000 ft. Although this data is not a complete record of the wells drilled, it does demonstrate a trend in the industry to continually surpass the 15,000-ft measured depth mark. By the end of 2005, more than half of the wells reported to the industry drilling envelope were deeper than the “superdeep” 1980s mark. This is a credit to the reliability of technologies used to reduce risks in these operations. The drillstring is among the components that can be regularly depended on to withstand the load at these depths.

Further, the first extended-reach wells took over a year to complete. Today, a 20,000-ft ERD well can be completed in less than 60 days.

As drilling challenges continue to evolve, new projects are now expected to achieve measured depths in excess of 50,000 ft. Among the technical limitations will be the capability to handle the torque required to drill on bottom and the tensile requirements to complete the casing plans. Both of these limitations involve further advancements in drill pipe technology.

The average measured depth of horizontal wells drilled in the US has increased from 2007 to 2010 from more than 10,000 ft to more than 13,000 ft. (Source: Spears DPO March 2010)

Drill Pipe History

Drill pipe is rarely considered to be a high-technology product; most of the industry refer to it as “dumb iron.” Drill pipe has, however, evolved significantly over the last 60 years. What was originally a simply threaded and coupled tubing product now has a highly engineered and controlled design.

To better understand how drill pipe has evolved from couplings and tubing to its current design, it is important to follow the design milestones.

The most significant drill pipe milestone occurred in the late 1950s, when the threaded and coupled design was eliminated in favor of the friction-welded design. The friction-welded design replaced the threaded tooljoint with the welded tooljoint, removing a significant stress riser at the connection. This design also allowed for new and more durable connection designs. The original connection designs were supplied by many manufacturers, and they were not all compatible. In the early 1960s, API standardized the connection and added additional fatigue design elements.

These two simple innovations reduced the fatigue failures and removed the drill pipe from being the critical restriction on potential drilling depths and well profiles.

Shortly after introducing these innovations, the average drilling depths in the US dramatically changed – going from 4,000 ft in 1950 to 6,000 ft in 1970.

For the next decade, there was little substantial change in drill pipe design to improve its performance or capabilities. The next major milestone was the evaluation and design improvements related to washouts near the internal upset in the drill pipe tube. Many studies were conducted and industry papers written to establish the root cause and develop corrective design features.

Drill pipe with MIUs shorter than 1 in. (25.4 mm) were found to often fail in less than 500 rotating hrs. In the mid-1980s, the API standard for drill pipe, API 5AX, did not attempt to control the minimum length of the internal upset, which resulted in the emergence of a variety of profiles, depending on the manufacturer. API now specifies a minimum MIU of 2 in., although today’s premium drill pipe can have MIUs that are over 4 in. in length.

This improvement, combined with internal plastic coating, has noticeably reduced the number of washouts in drill pipe. Although washouts rarely affect the ability to reach the drilling target, they create expensive difficulties during deepwater operations.

Industry drilling envelope records indicate a trend to continually surpass the 15,000-ft measured depth mark. (Source: K&M Technology)

Sour-service

The metallurgy of “high-strength” drill pipe has continued to improve over the last few decades. This includes vendors’ ability to tightly control the manufacturing process in order to predictably control the mechanical properties of the final product. Normalized grade “E-75” drill pipe and quenched and tempered “X-95” and “G-105” were the only choices for sour-service drilling until the early 1990s.

These grades of drill pipe, although acceptable for some sour-service drilling, were not ideal. Drilling with these grades of pipe in moderate or highly sour well environments often led to drillstring failures. The E, X and G grades also reduced industry’s drilling potential by limiting the maximum tensile strength of the pipe.

Today’s H₂S-resistant drill pipe can be used in almost all harsh sour drilling environments and include a variety of configurations to meet the level of sour resistance needed. Every section of the drill pipe can now be manufactured to some level of sour service. The tooljoints, tube body and even the friction weld at the upset can be controlled for some sour-service resistance.

Design work in this area continues to increase the drill pipe’s resistance to sour environments, and manufacturers expect that they will be able to begin to commercialize new sour-service drill pipe in the coming years that has a minimum yield above 120 ksi. New standards for sour-service pipe are being developed by NACE and the IRP drill pipe committee, which will require tighter controls of the metallurgy.

Figure 2: One drill pipe milestone came with the advance of the API double-shouldered connection, which helped to improve drill pipe hydraulic performance, torsional properties and OD.

Connections

Tooljoint connection technology remained largely unchanged from when API modified the connections to the NC connection in the early 1960s until the early 1990s. After decades of the average drilling depths staying nearly the same, operators began to push the torsional limitations of the drill pipe connection.  The industry quickly responded with a second generation of drill pipe connections. The new connections used the same taper and thread profile as the standard API “NC” connection but added a secondary internal shoulder (Figure 2), which increased the torsional capabilities of the drill pipe by over 40%.

The secondary effect of adding the internal shoulder was the ability to make the connection more hydraulically streamlined. By reducing the OD and increasing the ID of these connections, operators were able to use larger tube sizes of drill pipe, increasing tensile capacity in smaller holes.

Additionally, the new connections reduced the overall hydraulic loss per foot of the drillstring. On rigs where hydraulic or ECD issues limited the casing or drilling program, these improvements opened a new range of drilling possibilities. Our drilling programs regularly include this type of drill pipe to advance the drilling of horizontal wells, and this technology was included in many of the deep and extended-reach wells of the 1990s.

The next series of drill pipe connections offered an even slimmer profile, improving fatigue resistance, and further pushed torque and tensile capacities. These connections abandoned the API or NC taper and thread profiles for their own specific designs. Proprietary double-shouldered connections (DSCs) are now widely used in applications where the API drill pipe from the 1980s would not have been fishable or would have generated too much hydraulic pressure loss to complete the drilling program.

Table 2 shows the evolution and impact of the connection technology on 4-in. and 5 ½-in. drill pipe.  The standard NC38 connection using today’s OD and ID requirements would have only a makeup torque rating of 12,000 ft-lbs. The torsional ratio of connection to tube at 0.48 would be well under the generally accepted guideline for connection design and would likely not be a recommended configuration. The NC40 connection would be a suitable alternative but requires a larger tooljoint OD. This change in tooljoint OD complicates any potential fishing operation in 6 ¼-in. hole and increases the hydraulic losses to almost 1,700 psi per 1,000 ft.

By switching to the API double-shouldered connection, the hydraulic performance, torsional properties and OD are all improved. This can be further improved by advancing to the proprietary versions of the drill pipe connections.  These connections further “slim” the connection profile and improve performance metrics by 10% more. Today’s advances in connection technology are focused on reducing the time required to make up the connection and enhancing fatigue resistance. Even with the planned improvements, most downhole equipment designers strive to develop tools as strong as and with similar fatigue resis tance as the drill pipe they are carried in. Drill pipe performance metrics are used to determine whether the bottomhole assembly tools are oilfield ready.

By the end of 2005, over half of the wells reported to the industry drilling envelope were deeper than the “super deep” 1980s mark. (Source: K&M Technology)

Other enhancements

Drill pipe has evolved to continually stay ahead of industry’s drilling requirements, and manufacturers continue to add design features into what many consider to be a simple product. They have developed innovative methods to include a “slip proof” section to eliminate slip crushing while under significant loads in excess of 2 million lbs. Current landing string technology allows for the manufacture of 6 ^5/8-in. drill pipe with wall thickness nearing 1 in. and minimum yield strength above 165 ksi.

New developments in thin-walled drill pipe significantly improve the strength-to-weight ratio of drill pipe. The addition of telemetry is also possible with “wired” drill pipe, which is poised to change the way the industry evaluates formations.

With all of these innovations from the past and more innovations on the near horizon, it is hard to think of drill pipe as “dumb iron.”

As discussed, ultra-deep wells (UDWs) and extended-reach wells (ERWs) are becoming more and more commonplace. Not only are they drilled with greater frequency, but they are also increasing in reach and depth. Drill pipe has historically been stronger than the forces and stresses placed on them – by far. With the increasing depth of UDWs and reach of ERWs, the technology and operating limits of pipe are being reached. Drilling practices in various areas around the world, such as gas shale plays in the US, are also challenging drill pipe limits.

This section will present examples of wells that have reached or exceeded the limits of today’s drill pipe, even with the proprietary DSCs, S-135 grade and advanced metallurgical and manufacturing processes. An example of torque limitation, tensile limitation, landing string stress and loading limits, and an ultra-ERW are presented. In each of these cases, the limitations of the pipe and the solutions sought will be discussed.

Figure 3: An example well drilled in the US in 2010 with this typical highly deviated and hold well profile experienced high torque despite not qualifying for the term extended-reach.

Torque Limitations

An example well in the continental US is representative of the highly deviated build-and-hold wells that are quite commonplace in the industry today. The deviation of the well approached 78° from vertical (Figure 3). It is interesting to note that this well, as with many other wells that were drilled in 2010, experienced high torque despite not qualifying for the term extended-reach.

The string of 5 ^7/8-in. pipe with XT 57 connections has a makeup torque of 57,000 ft-lbs. Torque-and-drag modeling prior to drilling showed the torque at TD to approach or exceed the makeup torque of this API DSC design (Figure 4). In this case, mechanical friction-reduction tools were eventually used to decrease the torque enough to drill to TD.

Figure 4: For a well drilled in the US in 2010, the string of 5 7/8-in. pipe with XT 57 connections had a makeup torque of 57,000 ft-lbs. Torque and drag modeling prior to drilling showed the torque at TD to approach or exceed the makeup torque of this API double-shouldered connection design.

Also of interest is that the production liner run to TD employed both roller centralizers on the liner itself and mechanical friction-reduction tools on the landing string. Despite this assistance, the liner experienced enough drag that it was set a couple of hundred feet above the target depth.

Tensile Limitation

Possibly the most severe tensile situation for pipe during a common operation is experienced by drill pipe used as landing strings while running long liners. In addition to the concern of exceeding the tensile yield of the pipe, slip crushing and handling issues must also be considered.  Common changes made in response to the large loads include thicker pipe walls, increased slip segment lengths and material grades stronger than S-135.

Although API requires new pipe to be built to greater than or equal to 87.5% wall thickness, service companies, operators and manufacturers commonly have established internal standards of greater than or equal to 95% wall thickness for “fit-for-purpose” landing strings. Material grades of 140 ksi and 150 ksi are available and are being used. 165-ksi steel is being aggressively researched for application in the field.

However, to handle axial loads in excess of 1.5 million lbs, more dramatic changes have become necessary. A paper presented at an SPE conference last year, “Deepwater and Critical Drilling with New Connection Technology,” discusses additional improvements made within the past few years for landing strings. The crushing loads placed on drill pipe can cause the pipe to fail in the slips prior to a tensile failure, necessitating heavy-walled slip sections. A dual OD tooljoint provides a larger area in contact with the elevator, which increases the capacity of the elevator to handle high tensile forces while also meeting the requirements for fishing.

The current limitation for ERWs and UDWs is approximately 40,000 ft MD. Maersk Oil currently has the longest shallow ERW, ExxonMobil has the longest intermediate ERW, and GNPP Nedra has the longest UDW. Projects are being evaluated by multiple companies around the world that are either unobtainable or almost unobtainable. One of these projects is evaluated below.

Several companies are evaluating the possibility of drilling ERWs from onshore to reach offshore reservoirs. Alternative solutions are to use an offshore structure or build an artificial island, both of which are challenging and extremely costly.

Figure 5: This torque profile for a typical extended-reach well from 2010 demonstrates the difficulty that torque can cause in an extended-reach well that pushes the envelope of what is achievable today.

Torque is commonly a limiting factor in drilling ERWs, although drag does come into play when running long casing strings and liners. Figure 5 demonstrates the difficulty that torque can cause in an extended-reach well that pushes the envelope of what is achievable today. The string shown is composed of 6 ^5/8-in., 5 ^7/8-in. and 5 ½-in., all with high-torque connections.

Any time an ultra-extended-reach well is planned, alternative materials are considered. Aluminum is a common point of discussion, along with titanium and composite pipe. With the introduction of steel grades above the common S-135, another discussion on thin-walled pipe has begun. Using 165-ksi material, it is possible to achieve the same strength as a standard joint of S-135 pipe with a reduced wall thickness. The lower weight of a thin-walled pipe reduces the normal forces that lead to higher torque and drag. Increased flow area through the pipe is another benefit.

The challenges come with the loss of wall thickness through abrasion, fluid erosion and corrosion. Each thousandth of an inch of wall thickness lost with high-strength, thin-walled pipe is equivalent to a larger loss in a thicker S-135 equivalent.

With drilling programs reaching or approaching the technical limits of the drillstring, several industry changes have occurred over the past decade, most notably the increased focus on drill pipe inspections, which have increased in frequency and scope. Several organizations, including TH Hill and Fearnley Proctor, have developed industry-accepted standards for the inspection of drill pipe. These standards are widely used to ensure the pipe will meet the high demands of newer drilling programs.

This extended-reach well path from 2010 is typical of a well drilled from onshore to reach an offshore reservoir.

API recently completely revised its recommended practice for drill pipe inspection in API RP 7G-2, including several categories of inspection. Along with the addition of these new inspection standards, a new third-party inspection “audit” service industry has been created.

The frequency of “critical” drill pipe inspections and “audits” of these inspections is on the rise. Many of the critical drillstrings are required to have a minimum 95% remaining body wall to be sufficient to meet operational demands.  These drillstrings already include improved material grade technology and improvements to wall thickness but are allowed less than a 5% reduction in wall prior to being deemed “not fit for purpose.”

It is clear that advances in these critical drillstrings are needed. As industry attempts to move forward and further its drilling programs, collaboration between operators, well planners, drill pipe manufacturers and service companies must be expanded.

Over the last 50 years, drill pipe tensile and torsional capacities have typically exceeded industry’s needs in most drilling applications. Drilling has continued to trend toward drilling deeper, longer-reach wells. Although improvements in drill pipe, performance and connection technology have significantly advanced, industry’s drilling programs have begun to push the limits of drill pipe capacities. Without further improvements to materials, connections and fatigue life, the drill pipe could become the limiting factor in exciting new projects on the horizon.

It is essential that suppliers, including rental companies, and manufacturers, play a larger role in well planning to mitigate these limitations and make sure the technologies required are available to the industry in time to coincide with the new drilling projects.

By Keith Womer, KWTS; Dustin Torkay, Gino Villanueva, Seawell Americas; Thomas Geehan, M-I SWACO; Jan Brakel, Shell; Dimitrios Pirovolou, Schlumberger; David Reid, National Oilwell Varco; Mike Killalea, IADC

Stick-slip workshop participants are grouped by age.

This article presents the results from a workshop on stick-slip mitigation held in Houston on 15 July 2010. Sponsored by the Future Technology Subcommittee of the IADC Advanced Rig Technology (ART) Committee, the event brought together technology leaders and engineers to discuss stick-slip mitigation.

Led by specialists with operating and technology companies, the goal was to educate the industry regarding existing technologies available to address this issue, as well as identify the need for possible future technologies. In addition to presenting the findings from the workshop, this article also aims to describe the event’s unique structure:

• Opening, non-commercial presentations wherein the science of stick-slip and the business case for its mitigation were reviewed;

• A series of short presentations by various providers with technologies to identify or mitigate stick-slip;

• A roundtable discussion involving both the presenters and the audience to assess the effectiveness of these technologies and areas where further technology, education or process improvement is needed.

This was all condensed into one afternoon. It was the first in a series of planned workshops to address technology needs that were identified in an industry survey conducted by the IADC ART Committee last year and reported in IADC/SPE 128953, presented at the 2010 IADC/SPE Drilling Conference in New Orleans.

Figure 1: The IADC Future Technology Subcommittee follows a three-step process to encourage technology commercialization and increase the industry’s technology adoption rate.

Background

The mission of the IADC Future Technology (FT) Subcommittee is to encourage technology commercialization and increase the industry’s technology adoption rate, focusing on high-need applications. This process consists of three phases (Figure 1):

• Phase 1 analyzes case studies of successful technologies, so-so technologies and unsuccessful technologies.

• Phase 2 conducts industry surveys regarding technology needs online and at industry conferences.

• Phase 3 actively addresses technology through publications and workshops targeted at specific high-need areas.

Figure 2: Representatives from service companies accounted for 61% of attendees, which may have biased results from the survey questions.

At the 2010 IADC/SPE Drilling Conference in New Orleans, the FT Subcommittee presented a paper that assessed examples of past, present and future technology commercialization and summarized results from its 2009 technology-needs survey. Results indicated that stick-slip mitigation technology was in high need, and the group decided that a half-day workshop would be the best format for bringing together leaders of different technologies to help educate the industry on available solutions.

The afternoon format was a critical factor for the success of the workshop, and its popularity was largely unexpected. It appeared to have been popular primarily because most attendees would not have to miss an entire workday. Additionally, because the workshop was only four hours, content was condensed into a dense, high-value format with little overlap on topics or presentations.

Figure 3: A significant majority – 85% – of attendees surveyed said there was a strong business case for stick-slip mitigation technologies.

Another somewhat unusual aspect of the conference was in its approach to commercialization. One of the sessions was devoted specifically to providing vendors of slip-stick mitigation technologies an opportunity to present a brief overview of their solutions. It was felt that this was an efficient means, both for the vendor and attendees, to present basic information regarding various technology offerings on the market. Commercialization beyond this narrow scope was not permitted.

The workshop consisted of the following sessions:

• What is stick-slip.

• The value of stick-slip mitigation explored with case studies.

• Technologies that address stick-slip mitigation.

• Roundtable discussion.

• Knowledgeable and well-rounded speaker representation with open discussion.

• Networking hour.

Figure 4: Most attendees agreed that the effectiveness of stick-slip mitigation technologies ranks high in importance.

Background and prejudice of participants

There were a total of 106 attendees, most of whom were local to the Houston area. A survey was conducted at the end of the workshop, completed by 51% of attendees. The survey provided a good estimation of the demographic makeup of the participants and measured their opinions regarding the workshop format and technical content.

The survey revealed that 61% of participants were from service companies (Figure 2). Approximately 18% of participants were from drilling contractors and operators, and 90% of all participants found the workshop to be very/somewhat valuable.

Figure 5: More attendees saw a middling importance for the cost of stick-slip mitigation technologies.

The large representation of service companies could have biased results for some of the survey questions where participants were asked to evaluate what they think the most effective and cost-effective technologies presented were (Figures 8 and 9).

This session was designed to be a tutorial regarding stick-slip, specifically what it is in the context of general drillstring vibration, how it is detected and typical techniques for mitigation.

Figure 6: Workshop attendees saw the importance of training for stick-slip mitigation technologies as being relatively high.

One definition for stick-slip is that it “refers to the phenomenon of a spontaneous jerking motion that can occur while two objects are sliding over each other.” In the drilling industry, it is characterized by large cyclic variations of the drive torque and the rotational bit speed.

The technical discussion was presented by John Macpherson from Baker Hughes. He outlined the characteristic drilling responses that identify the condition, drill bit stalling and the significant variations in torque. A remedy to remove the effect is by decreasing the weight on bit and increasing rotational speed.

An example of the worst case was quoted as 24 seconds with no bit movement and 1.4 seconds of backward drill rotation. After nine hours, the tools were destroyed – illustrating that the subsequent effect of stick-slip on tools in the drillstring can be very severe.

Figure 7: The reliability of stick-slip mitigation technologies was seen to have a high level of importance by most attendees surveyed.

Mr Macpherson also remarked that slip-stick vibration and lateral vibration are inversely coupled, meaning that often a decrease in stick-slip may result in an increase of equally harmful lateral vibration. Hence, “stick-slip mitigation” is actually a balancing act that involves trading off slip-stick and lateral vibration to establish an operating environment that minimizes both but perhaps not eliminating either.

The second presentation, by Mark Dykstra of Shell, addressed the business value of mitigation of the stick-slip effect. Primarily, the justification was based on the cost-per-unit depth analysis. The related effect of wear on the dull tool was highlighted by the option of increased rotational speed.

Figure 8: Surface monitoring with downhole information was perceived as the most effective stick-slip mitigation technology.

The presentation went on to describe the auto-mitigation technique known as Soft Torque Rotary System (STRS). This works on the transfer function of speed and torque. An example of its use on an offshore well in Qatar was described. In that application, the use of the technique resulted in a 42% improvement in ROP.  Shell has resumed active sponsorship of deploying the latest soft torque rotary system technologies – a sponsorship they pioneered in the 1990s.

The presentations in this session were from vendors of stick-slip detection, analysis and mitigation technologies. They ranged from basic monitoring to analysis services (frequently bundled as part of an overall vibration management service) to soft torque control systems.

Figure 9: Soft torque systems were perceived as being the most cost-effective stick-slip mitigation technology.

In the first presentation, Ryan Weeden of NOV ReedHycalog discussed how the effect of stick-slip can be reduced by the correct design of the drill bit and bottomhole assembly. More drill bit contact area with the annulus wall can help to decrease torsional vibration and thus stick-slip. Additionally, the use of a stiff assembly will decrease the deflection of the string, causing natural frequency changes that can help to mitigate stick-slip.

In the second presentation, Svein Ove Aanesland from National Oilwell Varco described a soft torque control system that modulates the top drive drilling motor while using sensors to determine the rotational speed and torque and incorporating simulation software.

He also described the difference between AC and DC top drives and the internal damping from each. When comparing two nearly identical wells drilled in the same formation, the DC top drive outperformed the AC top drive in terms of higher ROP and reduced bit wear due to “droop” or more dampening inherent to DC motors.

Figure 10: Most survey respondents considered stick-slip mitigation technologies to be most effective as an aid to current methods.

In the third presentation, Scott Boone from Canrig Drilling Technology presented his company’s implementation of a soft torque control system. In general remarks, Mr Boone explained how the driller needs the correct suite of tools to reduce inefficiencies.

Improvement in tool performance comes from automation and optimization, resulting in greater safety and the reduction of flat time. All combine to reduce well costs. In the case of stick-slip, Mr Boone stated that between 20% and 70% improvement in ROP can be obtained with an automated soft torque system.

The value of non-commercial presentations were ranked on a scale of 1 to 5.

The last two presentations were delivered on the topic of vibration monitoring, by Riaz Israel from Schlumberger and Jorge Delgadilla from Geoservices. The use of both surface monitoring and downhole sensing were discussed. The use of high-frequency data acquisition was discussed, and it was stated that the measurements should be taken as close to the sources as possible to improve accuracy.

From the data acquisition, results need to be communicated and protocol procedures have to be implemented, with the supply of support and suggestions. These outputs are based on the analysis of the data acquired both surface and downhole.

The roundtable discussion included all speakers. Along with scripted questions, comments and questions were taken from the audience. The scripted questions were:

Unique in its approach to commercialization, the workshop allowed brief presentations by vendors. The presentations were ranked on a scale of 1 to 5.

What level of expertise and training is required to run these systems?

It was noted that soft torque control system products featuring an on/off switch have an inherent simplicity: “Try it. If it seems to help, great. If not, switch it off, no harm done.” Nonetheless, it was acknowledged by all that such systems don’t address every situation; therefore training and services will still have to be given to rig personnel to recognize a situation, determine the root cause and identify and implement a solution.

Given the current solutions for stick-slip mitigation, what else should be done?

The following points were made by various panelists:

• Further gains could be made if companies work with each other and try to control both rotational speed and weight rather than each alone.

• Further coaching is needed regarding tool limitations to avoid unsafe tool use.

• The use of high-resolution data – as is available with wired pipe or in recording tools – was encouraged.

• A recognition of the interrelationship of torsional vibration and lateral vibration is important.

• There are other variables that were not fully covered in earlier discussions, such as well shape and hole size, that need more study.

Workshop participants were asked to assess the roundtable discussion. The discussion was ranked on a scale of 1 to 5.

What improvements can enhance the systems shown today?

The following points were made by various panelists:

• With more runs in various drilling situations, more experience will be gained.

• The control systems still need checks so that wrong inputs can be regulated.

• The situation downhole is still a blind one. We can’t really see what is happening downhole. Anything to improve understanding will move the industry forward.

• Wired pipe and real-time data to reduce latency would be an immense help.

• Having vibration monitoring on different points in the drillstring would aid understanding of vibrations.

Overall technical content of the workshop was ranked by participants on a scale of 1 to 5.

What level of detection and mitigation seems to be the most cost effective?

The moderator acknowledged this as the “unfair question,” which nonetheless is one that was on the minds of all of the attendees.

The following responses were made by various panelists:

• Regardless of other analysis and mitigation, bit optimization needs to take place.

• However, bit optimization is still limited by other components.

• “Cost effective” must be measured against acceptable risk: In most cases, the cost of having to fish or saving one trip can cover the cost of analysis services or one of the software torque control systems.

54% of workshop participants found the workshop to be very valuable.

Where should the future of stick-slip mitigation be invested and directed?

Following were the recommendations of the panelists:

• Operator training and planning.  For example, with a rotary table, everyone knows when stick-slip is happening because everybody can feel it. However, an AC top drive will power right through it, making detection difficult; therefore operator training is important.

• Broadening system application.

• Educating people on the benefits and problems of stick-slip.

• Improved planning.

• Use of real-time measurements, such as wired pipe, as a way to “close the loop” not just for stick-slip but all modes of vibration.

Comments taken from the audience included:

• Rig culture considerations, such as drilling parameters dictated by the company man, need to be considered.  Sometimes when drillers notice a stick- slip condition, it is ignored, deviating from the dictated drilling parameters.  Managing the decision-making process can help alleviate cultural problems.

• Control systems such as soft torque assume the driller has some autonomy and is proactive.

• There is no perfect solution.

• Proper well planning and design of bit, BHA, mud, ROP and WOB can solve many problems.

The overall conclusion from the workshop is that there is no single solution to stick-slip mitigation with current technologies. However, services and control systems can offer a cost-effective benefit in certain situations. Given that there is no “silver bullet” at this point, rig training is still required to recognize and mitigate stick-slip. More field experience in the use of soft torque systems will improve the effectiveness of the systems.

Additionally, the use of real-time downhole data is the frontier that could result in a step-change improvement in management of the multiple modes of drillstring vibration.

The Stick-Slip Mitigation Workshop was a success due to excellent speakers, engaged participants, a focused and compact agenda, and presentation and analysis of a variety of technologies that can help mitigate the costs of drillstring vibrations. 50% of attendees surveyed said the workshop was very valuable, 40% said it was somewhat valuable, and 10% said it was just OK.

Overall, these responses were positive, and the IADC Future Technology Subcommittee plans to host additional workshops for other high-needs areas.

By Hamayun Raja and Rich Dodds, Halliburton

Figure 1: First-generation real-time centers have already helped to reduce NPT costs related to downhole tool problems ($2.8 billion). To reduce NPT costs related to hole problems and stuck-pipe problems (a combined $18 billion), the industry must evolve real-time centers to incorporate remote workflows that make use of all data to make better decisions.

One of the biggest economic challenges for an operator when drilling a well is to reduce nonproductive time (NPT). NPT represents lost opportunity and reduces return on investment. Over the past decades, various attempts have been made to reduce NPT. Remote operations is one such attempt, where operations are moved from offshore to onshore; this often requires a redefinition of workflows and methods.

Real-time centers (RTCs) used to be  primarily focused on improving service providers’ tool reliability and service quality, but today they serve mainly as data collection and operations monitoring centers. The challenge now is that operators are overwhelmed with the amount of information presented. RTCs must be put to better use to further reduce NPT.

This article presents examples of remote workflows and how RTCs can be used to greatly enhance understanding of the subsurface environment. How real-time information can be used to reduce NPT will be discussed.

Integrated operations (IO) can go by several different names, such as e-operations, e-field, smart field, field for the future or digital oilfield. But they all mean more or less the same thing: the use of more advanced resources in a shorter period of time as a result of extensive collaboration and use of new technologies and integration of services to provide a solution. The use of integrated operations is also called a solution-based approach, where a set of services is provided to solve a field problem.

As land and conventional shelf resources become harder to find, drilling has become much more focused on unconventional and deepwater resources. A 2008 survey on E&P spending indicated that deepwater continued to increase relative to overall offshore budgets and that more companies intended to focus more on deepwater going forward.

Onshore, shale has already evolved into a major player in the North American energy portfolio, and projects are being launched in other areas of the world to drill for shale gas as well. Of the companies surveyed, 65% responded favorably regarding their views on the long-term outlook for natural gas drilling in North America. Deepwater and unconventional drilling both offer a challenge of using more integrated resources to save time and cost. IO revolves around the most important technologies within the industry to get optimized solutions.

Figure 2: A survey was taken to rank technologies in order of importance to users, and 3D/4D seismic received the greatest number of responses in 2008. Integrated operations revolve around using advanced technologies such as these through extensive collaboration to provide optimized solutions.

Over the past several years, more companies have begun listing 3D/4D seismic as an important technology (No. 1 in Figure 2); other top technologies were fracturing/stimulation (No. 2), horizontal drilling (No. 3) and directional drilling (No. 4). In addition, companies continued to place an increasing emphasis on reservoir recovery optimization technologies (No. 5).

A report published in 2007 by OLF, the Norwegian oil association, suggests the net present value of IO on the Norwegian Continental Shelf (NCS) is approximately $22.5 billion. An increase of just a 1% recovery rate on the NCS could result in increased income of $46 billion with oil prices at $75/bbl.

The heart of integrated operations is the RTC. Whether it is remote or operational, RTCs need to evolve from where they are today in order to really reduce NPT. Today, many RTCs are primarily focused on reducing quality issues related to service provider tools.

Figure 1 shows downhole tool-related problems contributed to $2.8 billion of the total drilling-related NPT. First-generation RTCs, which are an offshore/onshore interface, have contributed to lowering this part of the total NPT. Hole and stuck-pipe problems contributed to $18 billion of the total; the challenge now is to address this part of NPT to reduce total well cost.

RTCs need to evolve into centers where cross-discipline teams collaborate to solve drilling challenges, such as stuck pipe or hole problems, in addition to reducing service-quality issues. These teams need to work together through integrated workflows that allow all available data to be used to make better decisions. Further, results must be continuously optimized.

Three workflows that can be used today to help reduce NPT and place the well in the right spot are a digital consulting and collaborative well planning workflow,  a digital drilling workflow and a digital geosteering workflow.

Figure 3: In the workflow for collaborative well planning, a rough field plan is developed to hit the maximum number of targets. Plans are then validated for torque and drag, anti-collision and other considerations through the use of applications software. Results can be viewed simultaneously to provide a broad understanding of the development plan.

Collaborative Well Planning

The end product of collaborative well planning is the field development plan. After well plans have been developed, they can be validated for torque and drag, anti-collision and other design considerations through use of applications software. Figure 3 illustrates this workflow. For a field development plan where hundreds of wells are needed, footage drilled and pad locations can also be optimized to hit the maximum number of targets.

The rough field plans are then individually analyzed for detailed anti-collision issues. Analyses for torque and drag, hydraulics, pore pressure and tubing are performed. The results can be presented as a 3D view.

Planning in Utah

The Natural Buttes field in Utah has marginal economics. After encountering a collision and difficulty planning the lazy S-shape of the wells and hitting multiple targets, the operator looked for another solution. One complication was that pads could not be located within 150 ft of endangered cactuses in the area. Due to pad drilling and close spacing, changes to the plans after permitting slowed down the drilling process.

Halliburton Consulting used collaborative well planning to plan multiple scenarios and optimize existing pads, saving more than $30,000/well. If the operator had continued to drill the whole field with 7,000 wells, that would have been a savings of more than $200 million.

Planning in Pennsylvania

In Pennsylvania, well planning tools were used to quickly select locations in treacherous terrain for more than 400,000 acres, optimize the use of drilling slots within pads and increase lateral extent to hit more reservoir targets while reducing the number of pads. This resulted in savings of $45 million in pad construction and gained nearly 2 million ft of lateral length. More than 520 drilling days were saved, which reduced costs by more than $25 million.

The digital drilling workflow is focused on optimizing wellbore stability. An operator can customize its own digital drilling workflow to focus on critical issues and challenges expected.

Figure 4: Collaborative well planning was used for a field development in Utah, where multiple scenarios were generated and existing pads optimized. More than $30,000 per well was saved.

Figure 6 represents the workflow focused on the wellbore. Real-time data is streamed from the rig. A hydraulics specialist determines the real-time equivalent circulating density (ECD) from the incoming data and determines if the mud is in good condition. The specialist then provides the ECD information to the geomechanics specialist, who focuses on pore pressure, fracture gradient and wellbore stability issues. This helps the geomechanics specialist determine downhole conditions.

A bit specialist uses this information to determine the appropriate bit required. Choosing the wrong bit can cost an operator an extra trip, which could range from a few hundred dollars to hundreds of thousands of dollars depending on the location and well depth.

The drilling supervisor is responsible for keeping and updating the plan. His real-time input is provided by the hydraulics, geomechanics and bit specialists. The drilling supervisor compares the original plan from the collaborative well planning workflow with actual data and updates it with real-time parameters.

Figure 5: Collaborative well planning tools were used to optimize an asset in Pennsylvania, resulting in a savings of $45 million in pad construction and gaining nearly 2 million ft of lateral length.

Workflow advantages

One of the main advantages of this drilling workflow is that it operates in a proactive manner and can optimize the wellbore. The drilling adviser can compare the plan with real-time values in order to change the well direction before any problems occur. All the models for torque and drag, pore pressure, etc, are inherited from the collaborative well planning phase.

The goal of geosteering the well is to optimize well placement in order to get the maximum reservoir contact. Figure 7 shows the geosteering workflow.

Operators define the target zones for the geosteering operation. These boundary limits or payzone geological layers are either obtained from offset wells or seismic data. The real value of the geosteering workflow comes into play when new geological surfaces and faults are identified in real time while drilling.

Figure 6: Within a digital drilling workflow, real-time data is streamed from the rig to enable better decision-making. An operator can customize the workflow to focus on critical issues and challenges expected during the drilling of a well.

This new workflow provides the ability to move new faults and geological surfaces back to models and plans so they can be updated in real time and used for current or future well development. The operator can then view this new data and update the model while the geosteering engineer waits for new boundary instructions. By updating faults and surfaces in real time, operators can save time and better ensure optimal well placement.

Figure 7: This digital geosteering workflow can help to identify new geological surfaces and faults in real time while drilling, saving time and ensuring correct well placement.

Summary

Digitizing the oilfield is a concept of using digital resources in a shorter time frame as a result of extensive collaboration and use of new technologies and integration of product lines. The workflows discussed here are examples of such oilfield digitization.

The key to solving NPT challenges is contingent upon using specific workflows. Combining information from different services will help in overall performance and reliability and help to develop a new level of integrated operations. These workflows are independent of each other, enabling more flexibility and use of innovative technologies to address NPT challenges.

Shape memory polymer (SMP) materials are placed on the outside of a screen and measured. The advanced shape polymer sand control solution provides sand control without the need to pump an annular pack. Baker Hughes is putting SMPs through field trials.

Sand, a familiar adversary for drilling and completion engineers, continues to present a major obstacle to well production. It erodes hardware, blocks tubulars, creates downhole cavities and must be removed and disposed of. The challenge to control sand can cost tens of billions of dollars each year and represents an area of evolving technical expertise.

Sand control is playing a much bigger role in payzone management than in the past. According to Brad Baker, director of sand control systems for Baker Hughes, the realm of sand control has evolved to include systems and devices that are integral to understanding the pay zone, providing correct connections to the reservoir, enhancing the reservoir, maximizing reservoir conductivity and optimizing production.

According to Thomas Murphy, sand management services sales and marketing manager for Schlumberger, there is a growing trend toward open-hole completion techniques due to technology advances. “We are being asked to complete longer intervals with tighter pressure windows, along with the additional challenges we are encountering with shale,“ Mr Murphy said. “Because of this open-hole trend, we are seeing an increased demand for drilling with oil-based mud systems, which creates additional challenges with cleanup, displacement and debris management. This shift makes managing the transition from drilling to completing, and finally production, much more critical.”

“The industry continues to push us to do more in less time with cased-hole environments as well,” Mr Murphy said. Depending on the application, a variety of completion techniques are emerging where it is possible to complete long intervals at one time or to directly isolate and complete different zones separately in a single trip.

Advances to address potential and existing sand control challenges in all types of formations, both consolidated and unconsolidated, have been under development and range from shape memory polymers to increased application characteristics of resins for chemical consolidation. Baker Hughes, Halliburton and Schlumberger share some recent developments and case studies.

The use of shape memory polymers (SMPs) is undergoing field trials, Mr Baker said. Shape memory materials are smart materials that have the ability to return to their original shape after being introduced into a deformed state by an external stimulus or trigger, such as a temperature change. Sand management was selected as an initial application for SMPs because of its unique materials and properties. Due to the extreme environmental conditions that can be encountered in some wells, an improved SMP with transition temperatures, permeability and filtration properties suitable for downhole use was developed.

A device for use inside casing to control sand from entering perforation tunnels is also becoming available. Mr Baker explained that sand control media-filled telescoping devices connect the reservoir face to the production liner without explosive perforating charges, providing reliable full-bore sand control without gravel packing. Because there are no explosive perforating shaped charges, there is no resulting debris, no damage to the formation face, no sand control screens, no gravel packing and no high-volume/high-rate fluid pumping required, Mr Baker said.

A third technology, nanoparticles, has been in use in sand control applications for about a year. Baker Hughes’ nanoparticle fines migration control additive can be added to the proppant mix at the blender tub on the fly. Inogranic nanocrystals are capable of fixating formation fines, such as colloidal silica, charged and non-charged particles and expandable and non-expandable clays onto proppant particles.

Baker Hughes’ telescopic devices provide a viable alternative to perforation tunnels, allowing a direct connection to the reservoir without undue perforating damage.

The nanoparticle technology was used on a frac pack completion on a Gulf of Mexico well that had been producing sand for five months. The well, located in Green Canyon 157 in 2,618 ft of water, had a zone of interest with a reservoir pressure of 9,275 psi and temperature of 156° F. The well had been shut down and sidetracked as a result of major sand control and fines migration problems that caused production losses.

In this application of nanoparticle technology, the nanocrystals, having very high surface force interactions, readily attached to the surface of ceramic and silica proppant particles.  Approximately 97,000 lbs of 20/40 proppant were delivered through the perforations into the fracture.

After the frac pack was completed, the well was immediately brought back online with no sand control problems reported. The formation pressure, oil production and gas condensate production values returned to their pre-shutdown values.

Another advancement in sand control, the inflow control device, is used as a permanent part of the well completion to control flow from the reservoir to the wellbore along the length of the horizontal section. The device manages inflow by applying a resistance to flow at the reservoir face.

The Baker Hughes inflow control device was used in 2010 to maximize production and ultimate reserve recovery from a reservoir in Russia’s Eastern Siberian Verkhnechonskoye Field. Due to the lack of an active aquifer, a water-injection system was required to maintain the reservoir pressure. Because gas and water tend to cone toward the heel of the well, they can break through anywhere in the well because of permeability variation along the horizontal section.

Three wells, two producers and one injector, were completed in this field using an inflow control device. After drilling the candidate well, the actual permeability profile was built based on final logs, and the completion design was updated. Packer placement depth was selected to isolate high and low permeability. The number of inflow device joints was then determined to mitigate high inflow from the high-permeability zone and to allow flow with little completion resistance for low-permeability zones.

After an initial production period, the operator ran production logging tests in each of the three wells. Engineers then compared the actual with predicted inflow profiles for the same wells without the Baker Hughes inflow system. The inflow profiles indicated good increase in inflow performance. The ability to capture and understand the results and effect of the inflow performance of these wells resulted in the customer being able to develop this marginal field.

Damaged portions of screens can have large holes that allow proppant and formation particles to flow through. According to Halliburton, a cost-effective solution can include a wellbore clean-out followed by pumping of a chemical consolidation treatment to bond the proppant and/or formation solids that currently exist around the screen, preventing further flow.

According to Bart Waltman, global product manager for sand control fluids for Halliburton, most consolidation treatments are being applied as remedial applications in formation consolidation and repair of gravel pack, frac pack, standalone or expandable screen completions.

However, recent industry economic conditions have begun to make formation consolidation more attractive as the primary pipe and for completing marginal reserves.

Wells completed in weakly consolidated reservoirs that are susceptible to failure under production conditions such as excessive drawdown, depletion and compaction are candidates for formation consolidation to increase their unconfined compressive strength. In addition, formation consolidation can increase the cohesive strength between the grains and prevent sand production in friable formations at water breakthrough.

“To overcome challenges faced with early resin systems, internally catalyzed (IC) systems were developed,” Mr Waltman said. “These lower-viscosity solvent-based systems combine the resin and activator into one component that ensures successful consolidation takes place wherever the formation is treated.”

The latest resin chemical technology entails dispersing the formulation in an aqueous-based carrier (ABC). The low-viscosity ABC resin, which actively seeks out the contact point between the grains to maximize the bonding between the grains, offers advantages over solvent-based systems, he continued. These advantages include the ability to be foamed using nitrogen, that a large over-displacement is not required to reestablish permeability, and that a high flashpoint eliminates the need for special safety and operational procedures.

In 2009, an IC system was used on a well in East Kalimantan, Indonesia, completed in 4.5-in. casing. The reservoir was known for sand production when water was produced. The well was only able to produce sand-free at 1 MMcfd before it was shut in.

In the past, a through-tubing gravel pack would have been the sand control solution. Based on previous success with formation consolidation in a similar reservoir, an IC resin consolidation treatment was considered. This well was particularly challenging due to concerns that the viscous consolidation fluid could not be injected into the low-permeability formation without exceeding the fracture gradient of the formation.

However, after considering all parameters and with the view of performing sand consolidation treatments in offshore wells where reservoirs often have low permeability and high shale content, the operator and the Halliburton team decided to go forward with the treatment.

An optimized IC resin treatment was placed using coiled tubing across the 6.5-ft interval. After the treatment, the well was tested at 2.5 MMcfd with 70 bbl/day of water at 1,000-psi drawdown. Flow rates stabilized at 1.5 MMcfd and 50 bbl/day of water with no sand production.

Another IC resin treatment using the ABC formulation was used by an operator in the Gulf of Mexico. The operator required a rigless sand control solution for a bypassed reservoir in his existing wellbore, and the economics would not support a conventional workover gravel pack. After abandoning the existing completion, electric line perforating was used to access the 8-ft reservoir. Then a foamed ABC resin treatment was bullhead pumped down the existing production tubing. After the treatment, flow rate stabilized at 1.4 MMcfd with no sand production.

In the deepwater Gulf of Mexico, Schlumberger worked with an operator who required a solution to eliminate sand production and achieve low skin value in complex wells. The field was being produced from eight different wells. Six of those wells employed a single selective frac pack, with one using a stacked, commingled frac pack.

In an attempt to reduce the high costs associated with stacking frac packs in these deepwater completions, it was decided that the number of completions should be minimized by completing long, perforated intervals.

Fluidic oscillation technology is recommended for enhancing the placement of resin for formation consolidation. The oscillator generates alternating bursts of fluid to help achieve better penetration of the resin into the formation. Halliburton applied an internally catalyzed resin system to save an Indonesian well that had only been able to produce sand-free at 1 MMcfd before it was shut in.

The targeted wells featured multiple zones, resulting in complex directional wells with 50° to 60° maximum hole angles. The wells were completed using dry trees from a tension-leg platform and are produced primarily from massive, fine-grained, Pleistocene reservoirs. The reservoir can be characterized as unconsolidated and silty, adding to the complexity of the wells in the field.

To maximize well productivity with minimum solids production, the wells required completions with cased-hole frac packs. Sand control methodology was required to prevent the sand production at the expected drawdowns that were planned over the life of the well.

The completion design took into account the long intervals of the producing reservoirs, as well as the large variations in sand grain size and permeability. To reduce the high costs associated with stacked frac packs in multiple zones, the operator chose to complete the long intervals in single stages.

To ensure optimal proppant placement in the screen and casing annulus over the entire interval, the Alternate Path shunt tube technology was used to provide alternate, or redundant, gravel-pack slurry pathways. These pathways bypassed bridges and filled any voids in the gravel pack.

Because of the long completion intervals and the reservoir thickness, the potential for voids in the annulus pack was considered high. Small grain size added an additional challenge, making it difficult to balance obtaining high permeability in the annulus pack versus preventing sand production. Due to the challenges that were presented, a number of steps were taken to ensure the reduction of the potential for completion failure and sand production.

The Alternate Path shunt tube technology was selected to achieve the ultimate goal of propagating a fracture across most, or all, of the reservoir height with high pump rates, while ensuring complete gravel pack of the entire screen and casing annulus. As part of the screen design, shunt tubes were attached to the outside diameter (OD), which assisted with gravel packing the screen/casing-annulus sections of long intervals.

Schlumberger is leveraging current technologies, such as the ExxonMobil Alternate Path shunt tube technology, and applying it to open-hole completion applications when needed. The OptiPac system – the open-hole version of Alternate Path – is being used to meet the challenges associated with longer intervals, pressure limitations and shale.

The typical casing/screen geometry was an 8 ¹/16-in. OD liner with 6 ½-in. drift through the production interval, and with a 3 ½-in. OD base pipe premium screen inside. Two of the wells, A8 and A9, had larger production liners with 9 ½-in. and 8 ½-in. drifts. A 4 ½-in. OD base-pipe premium screen was employed for these wells, using a 7 ³/10-in. OD across the shunt tubes.

Through the use of the shunt tube technology, it was learned that thick, silt/very fine sand in highly permeable formations of over 500 ft could be successfully stimulated in a single stage. The job also proved that sand control integrity could be maintained by pumping high-rate frac packs and employing effective shunt tube technology.

The Alternate Path shunt tubes effectively eliminated sand production in all wells. With this technology, the operator was able to successfully stimulate the formation, achieving a low to negative skin value while ensuring a successful gravel pack over the entire interval. This exceeded the pre-project estimate of a skin value of five. Frac-packing multiple zones in a single stage and covering an interval of over 500 ft of the completed wells saved the operator an estimated five days of rig time per well. The process allowed the operator to produce additional reserves that may have been bypassed using conventional stacked completions.

Dealing with extreme kick/loss cycles is a given in the vuggy, fractured limestone of East Java’s Kujung formation. The difficult drilling is further complicated by reservoir gas with hydrogen sulfide (H₂S) concentrations up to 7,000 ppm and between 20% to 25% carbon dioxide (CO₂), all of which is compounded by a high population density in the areas surrounding the well sites.

To minimize the release of sour gas at the surface and to drill the hole into the target zone without damaging production potential, the operator used pressurized mud cap drilling (PMCD) in conjunction with a downhole isolation valve (DIV).

Use of the managed pressure drilling (MPD) methodology with surface-controlled valve technology has improved safety by greatly minimizing the amount of gas and fluid reaching the surface. Kick/loss cycles have been effectively managed, which allowed drilling to reach target depth with minimal formation skin damage. Recent MPD drilling operations have resulted in an absolute open flow potential relatively higher than previous, non-MPD wells and a significantly lower skin effect.

The rotating control device (RCD) equipment closed the circulation loop to allow pressure management even when tripping pipe. In the East Java application, the RCD was a passive type rated to 2,500 psi for dynamic conditions and 5,000 psi for static conditions.

Tough Experience

Exploratory wells drilled previously and conventionally in the field experienced significant problems with well control events. Much of the drilling budget was spent on cement and lost-circulation material (LCM) in efforts to mitigate circulation losses and the resulting kicks.

One of the exploration wells reached TD in about 230 days versus the planned 80 days. The many problems encountered included poor rig performance, shale sloughing, stuck pipe and severe losses in drilling the Kujung formation.

The experience benefited the next exploratory well drilled. Planned for almost 100 days, it took only 62 days to reach TD. But the well was not without problems. When drilling the 12 ¼-in. hole section to the top of the Kujung, severe losses of 60 bbl/hr to 600 bbl/hr were experienced along with subsequent kicks. Bullheading and well control operations were performed continuously for more than 20 days, including 19 cement plugs, before drilling operations could continue.

In addition, tripping the drill pipe in these conditions required killing the well to maintain control, which increased formation skin damage and compromised potential gas production. The alternative of snubbing – which would have eliminated formation damage by allowing pipe to be tripped in an underbalanced wellbore – was considered but rejected because of expense, long trip times and safety risks.

To resolve these challenges, MPD techniques, which involve drilling at balance or with a very slight overbalanced pressure, were selected. The MPD equipment spread was designed to minimize if not eliminate the release of sour reservoir fluids at surface. Included in the design was a downhole isolation valve to increase safety by isolating the reservoir during tripping operations.

Drilling plans specified the use of conventional drilling methods until losses were encountered and then called for a gradual shift from a conventional to a nitrified fluid. A PMCD methodology would be implemented depending on the degree of circulation losses encountered.

The PMCD variant of MPD technology allows drilling to continue during severe or total fluid losses. It is an effective alternative to time-consuming, loss-kick-cure cycles that are problematic in conventional operations. The technique takes advantage of the natural ability of the fractured formation to accept the drilling fluid and drilled cuttings instead of trying to cure these losses.

PMCD typically uses a viscous, weighted mud cap in the annulus to hold the reservoir pressure in balance while simultaneously pumping sacrificial drilling fluid (normally water) down the drill pipe. There are no returns to surface because the sacrificial fluid and all cuttings are lost into the formation.

With PMCD, drilling operations are conducted conventionally until severe losses are encountered. The system does not interfere with conventional drilling equipment or procedures. PMCD differs from a conventional mud cap in that the annulus fluid column is weighted to deliver a hydrostatic pressure slightly below the reservoir pressure. This results in a slight annular backpressure that is held by a rotating control device (RCD) at the surface. The backpressure is monitored to record changes in reservoir pressure and detect annular gas migration. When a predetermined pressure value is reached, pressure is managed by adding fluid to the annulus.

Hazardous formation gas was isolated behind a downhole valve made up as part of the casing string.

Isolating the Hole

DIV technology is used to enhance safety while tripping wells drilled in underbalanced or managed pressure modes. It is a surface-controlled device made up as an integral part of the casing. With the same inside diameter as the casing, the full-bore device allows the passage of downhole tools when it is in the open position. It is basically a flapper valve with a metal-to-metal seal rated to a differential pressure of 5,000 psi and a temperature of 300° F.

The DIV is opened and closed by hydraulically moving an internal sleeve via two ¼-in. lines run in the casing annulus from a surface control unit.  The hydraulic lines are clamped to the casing using cross-coupling clamps that protect the control line from abrasion.

The DIV has been used globally in more than 200 applications, where it has reduced operational costs and increased safety. The valve saves time by eliminating the need to circulate kill fluid into and out of the well while still protecting against potential swabbing and kicks while tripping.

Used with the PMCD technique, the DIV eliminates the need to kill the well before pulling the bottomhole assembly out of the hole – often a very lengthy, expensive and sometimes futile process when multiple trips are required in severe circulation loss conditions. In addition to tripping drill pipe, the DIV provides a means of safely and efficiently running and installing the completion assembly in a live well.

PMCD and DIV technologies have been successfully merged and implemented in onshore drilling operations in other parts of Indonesia. This East Java application extends the use to a more challenging setting involving a sour-gas reservoir.

The MPD equipment used in the field consists primarily of a simplified RCD surface equipment spread and the DIV. The RCD is positioned on top of the BOP stack together with the ancillary equipment required for the PMCD application. The RCD device closes the circulating system loop by sealing around the drill pipe and redirecting fluid and gas flow away from the rig floor, which allows drilling and tripping operations to continue while maintaining pressure on the well.

In contrast with a conventional circulating system that is open to the atmosphere, the closed-loop MPD system uses the incompressible drilling fluid in the wellbore to almost immediately convey downhole pressure fluctuations to the surface or, conversely, to change downhole pressure by applying backpressure to the annulus, without the need for manipulating mud weight.

In this application, the RCD was a passive type rated to 2,500 psi for dynamic conditions and 5,000 psi for static conditions. The RCD has connections for a 7 ^1/16-in. flow line, a 2 ^1/16-in. auxiliary line and a 13 ^5/8-in. bottom flange. Valves and pipework consist of a manually and hydraulically operated 7 ^1/16-in., 5,000-psi full-bore flow line plus two sets of 2 ^1/16-in. hydraulically operated valves for the trip tank and injection lines, along with pipework, elbows, connections and fittings that are attached to the RCD.

A 9 ^5/8-in., 47-ppf, 5,000-psi DIV was run as an integral part of the 9 ^5/8-in. intermediate casing string. With the valve closed and well pressure isolated below it, surface pressure is released and pipe is tripped in or out of the well at conventional speeds without swabbing effects on the lower open-hole interval. The need for pumping well control fluids is eliminated.

With the DIV closed, MPD equipment can be removed and BHAs changed even if the well is trying to flow. Once the BHA has been changed, it is tripped back into the hole to the depth of the DIV.  The well is then closed at the surface using the RCD equipment, the DIV is opened, and tripping the BHA into the well continues. A similar procedure is performed when running the completion assembly.

The RCD, valves and pipework needed for PMCD were installed before drilling out of the 9 ^5/8-in. casing so that return fluids from the 8 ½-in. section could be contained and diverted. The system also provided a precaution in the event that losses were encountered drilling into the top of the Kujung formation.

To reduce the chance of losses, the well plan called for penetrating the top of the Kujung as little as possible before setting 7-in. casing. If losses were encountered when penetrating Kujung, the objective was to control them with LCM so that mud could be kept in the hole and the casing run.

Using water instead of mud was a last-resort contingency due to the possibility of an adverse reaction from the interbedded shale/limestone formations directly above the Kujung. In that event, MPD equipment provided the means to trip the BHA above the reactive formation before introducing water. In contrast, severe or total losses in the 6-in. production hole required only a shift from mud to water and changing to MPD for pressure management.

Exploratory wells previously drilled using conventional techniques in this field in Indonesia’s East Java experienced significant problems with well control events. Because of poor rig performance, shale sloughing, stuck pipe and severe losses, one of the wells reached TD in 230 days rather the planned 80 days.

MPD with Casing Valve Operation in East Java

For the well recently drilled in the area, both the RCD and DIV were in place prior to drilling the reservoir section. The DIV was installed permanently as part of the 9 ^5/8-in. casing string at 1,901 m and 19˚ inclination. The overpressured thick shale above the subnormal, naturally fractured limestone was addressed with two casing sections. This change to the conventional well design improved drilling by resulting in a 6-in. open hole in the reservoir section.

The MPD operational outline for the well called for conventional drilling methods in the 6-in. hole until losses were encountered. A gradual shift from a conventional to a nitrified fluid was then planned, with a change to a PMCD system depending on the degree of circulation losses encountered.

Drilling the 6-in. section started and proceeded conventionally until partial and then total circulation losses were encountered. After pumping mud and water with no returns, gas was flowed through the separator and flared. However, the detection of sour gas at the surface prompted the cessation of drilling, and the well was shut in with surface pressure at 2,870 psi.

PMCD methods were implemented immediately once total losses were confirmed in the lower hole sections. This step eliminated the use of nitrified fluids, which had limitations in terms of equipment and LWD/MWD performance.

Well control and kill steps used annular pressure to force the sour fluids back into the reservoir. Fresh water was bullheaded into the annulus until the annular pressure was reduced to less than 200 psi. Drilling then continued using PMCD methods for approximately 100 additional meters.

To ensure that cuttings were being circulated into the loss zone, high-viscosity pills were pumped in the middle of each stand and before every connection. However, at target depth, the drillstring stuck in the hole. Data indicates that there were no significant increases in torque or casing and standpipe pressures, and during PMCD operations the cuttings were not plugging the fractures. However, it was determined that more detailed post-TD PMCD procedures were required, along with closer adherence to conventional hole-cleaning practices.

Attempts to free the string were unsuccessful, and ultimately the BHA was left in the hole. The subsequent fishing job, which involved numerous runs, was performed in PMCD mode and through the DIV. After each fishing run, the fishing assembly was pulled above the DIV and the valve closed, allowing the assembly to be tripped out of the hole without swabbing pressure. Once the tools were tripped out, the DIV was opened so that constant annular pumping could be used to keep the sour reservoir fluids in check.

When fishing efforts failed, a cement plug was set above the abandoned BHA. A drill stem test (DST) was then performed through the DIV. Once the DST operations were completed, the well was temporarily plugged and abandoned using the RCD and DIV equipment. Throughout these operations, the DIV was cycled 47 times, with much of that under pressure.

Recent drilling operations in East Java have shown the effectiveness of combining PMCD and DIV to drill difficult wells to TD and complete them while minimizing reservoir H₂S and CO₂ gas at the surface. In drilling the vugular, fractured limestone, the ability of PMCD to continue drilling despite severe and total fluid losses significantly improved safety and efficiency, reduced mitigation time and materials, and avoided formation skin damage.

Dr Lee Hunt, IADC President

As we approach the first anniversary of the Macondo tragedy, the drilling industry remains far from back to normal. The US Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE) issued the first deepwater drilling permit in late February – a positive step, to be sure. Yet much uncertainty remains, and numerous investigations into Macondo are still ongoing.The National Commission on the BP Deepwater Horizon Oil Spill issued its findings in January, and commission chief counsel Fred Bartlit followed a month later with his own report. Nobody can predict what concrete actions or regulations these reports will ultimately bring about.

And there is much more to come.

The National Academy of Engineering, conducting an investigation at the request of the Interior Department, issued an interim report last October and is expected to issue its final report in June.

The joint investigation team of the US Coast Guard and the BOEM Marine Board of Inquiry says it anticipates releasing a report in July focusing on forensic analysis of the subsea BOP.

An inquiry by the Chemical Safety Board, at the behest of the House Committee on Energy & Commerce, is still under way.

Under the Department of Justice, both a criminal investigation and a civil suit are ongoing.

There are also numerous congressional inquiries in progress, with proposed bills that could bring additional drilling restrictions or affect oil companies’ liability limits.

On the international arena, the governments and regulators of many countries are on the alert. So far, most of them have not taken drastic actions while waiting for official reports to come out of the US. That is about to change. With 20 April around the corner again, many of these countries are beginning to anticipate taking action.

We expect that in Europe, especially, the European Union, the Petroleum Safety Authority of Norway and the International Regulators Forum will begin parsing the various US reports and making recommendations of their own.

This is on top of continuing improvement efforts already under way within industry, whether it’s the Joint Industry Task Force, OGP’s Global Industry Response Group (GIRG), or Oil & Gas UK’s Oil Spill Prevention and Response Advisory Group (OSPRAG).

Macondo was an event that will have monumental effects on this industry for years to come, irrespective of national borders. Wherever possible, IADC will work to ensure the drilling industry has a prominent seat at the table to influence the coming changes. We’ve only just begun.

By Keith Smelker, Shell; Connie Burch, Mark Freeman and Floyd Felderhoff, Baker Hughes

A drill bit solution using a combination of tungsten carbide inserts and a steel tooth cutting structure helped to significantly improve the penetration rate in drilling the abrasive 8 ½-in. section in the Pinedale. A 20-hr decrease in drilling time was achieved for the interval. (Images courtesy of Baker Hughes)

Drilling at a high penetration rate while maintaining durability to complete abrasive sand sections in the Riverside field of Pinedale, Wyo., has been a challenge. The introduction of a new line of drill bits into the Pinedale area using a combination of tungsten carbide inserts (TCI) and a steel tooth cutting structure has led to increased performance, reduced risk and cost savings for the operator.

By combining the two cutting structure types, the drill bit was able to attack the formation more efficiently while resisting abrasive wear in key areas to drill longer-footage intervals. Improving the durability of the drill bit also helped to reduce the risk of losing cones, decreasing nonproductive time lost to fishing.

A typical well is drilled with an S-curve profile to gain displacement from the multiwell pad. The 8 ½-in. roller cone bits are normally used to drill the directional part of the hole using directionally steerable downhole motor assemblies. Once the well has returned to vertical or reaches casing point, the bits are pulled.

Using the service company’s design application review team process, the team of engineers and field support personnel from the operator and service company was able to identify the key limiting issues and make recommendations for the design of two different drill bits. These limiting issues were related to erosion and coring of the center of the drill bit.

The drill bit designs used both traditional and nontraditional cutting structure features, along with improved drill bit hardfacing materials.

Based on field observations and results, this article describes the initial benchmarking and field analysis, along with recommendation for design improvements. The results will be shown by comparing current field results with previous benchmarks. These improvements resulted in a 52% rate-of-penetration (ROP) increase in the first TCI run of the interval and a 59% increase in the second run. This improvement delivered a 20-hr decrease in drilling time over the entire 8 ½-in. section, significantly reducing the cost to drill that interval.

The Pinedale Anticline is in the Greater Green River Basin, south of the city of Pinedale, Wyo., and north of the Jonah Field in Sublette County. Production in this field predominantly comes from the Lance and Mesaverde formations. The wells are constructed with 9 ^5/8-in. casing set in 12 ¼-in. surface hole at 2,500 ft true vertical depth (TVD).

The 7-in. intermediate casing is set in 8 ½-in. hole between 7,500 ft and 10,000 ft TVD. The 4 ½-in. production casing is set in a 6-in. hole between 13,000 ft and 14,000 ft TVD.

To find an optimized drill bit solution for the Pinedale’s Riverside Field, the service company assembled an integrated, multifunctional Design Application Review Team (DART) to identify specific drilling problems and limitations.

Multiple S-shaped wells are drilled from a single pad, with the tangent section generally drilled at less than 30° from vertical. The kickoff point varies, with the build usually completed in the surface hole and the remainder of tangent and drop to vertical completed in the intermediate hole. The production hole is drilled vertically to total depth.

Two 8 ½-in. Vanguard TCI drill bits are generally used to drill through the intermediate section of the Fort Union formation to the top of the Lance formation. The Fort Union formation in this area is sorted sandstone interbedded with siltstone and stringers of extremely abrasive sandstones.

The mud system is inhibited clear water, with viscous sweeps made at every stand. The bottomhole assembly is a conventional, directional assembly using a bent housing motor with stabilization at 30 ft and 60 ft. The first TCI bit drills from surface casing at about 2,600 ft to 6,000 ft, and the second continues to drill to about 8,000 ft.

If intermediate casing is not set, the mud system is displaced to oil-based mud and the section is finished with an 8 ½-in. polycrystalline diamond compact (PDC) drill bit. The drilling parameters for this section are:

• 35,000 lbs weight on bit;

• 45-55 surface RPM;

• 155-185 total RPM;

• 500-525 gal/min flow rate.

Historically, this is a challenging section to drill due to the abrasive stringers. There have been multiple instances where the cones of the roller cone bit were lost and fishing operations were required.

Typically, the bit runs are limited to 35 hrs, if not pulled earlier for a torque spike, which is an indication that the drill bit has a mechanical issue. Trials to replace the two TCIs with one PDC of equal or higher gross ROP have been unsuccessful, with dulls often damaged beyond repair.

Prior to implementing the DART design, abrasive sands would erode the cone steel of the TCI bits. This led to potential coring and loss of cutting structure.

Design Application Review Team (DART)

A cross-functional team made up of participants from the service company’s applications engineering, research, product development, design engineering and operations groups was assembled. The design application review team’s focus was to address unique drilling problems and achieve customer objectives with an optimized drill bit solution. The team worked to identify the drilling problems and limitations posed by the application, then applied appropriate technologies

to eliminate these issues. Initial steps were to review the application and current use of the drill bits. These included 8 ½-in. MXL-S11G TCI drill bits, which were being used in the directional portion of the wells to cut through the abrasive sands sections. The review included observations of the used drill bits, discussion with the end user or customer and the actual performance of the bits.

During this review, it was determined that the drill bits were performing well with respect to penetration rates and distance drilled.

The issue with the bits was seen in the final dull condition as the cone steel was eroded while drilling through the abrasive sands. This in turn would lead to potential coring and loss of cutting structure if the runs continued long enough in the sands. The largest risk of this condition was the loss of cones as the center compacts lost their grip and fell out.

Once the problems were defined, the team outlined potential solutions and an action plan, which included combining the traditional TCI cutting structure and a steel tooth spearpoint in the cone with improved erosion resistance from new hardfacing materials available in the drill bit industry.

By combining the best of the two cutting structure types, TCI and steel tooth, the bit could capitalize on the best features of each. The outer TCI part was designed to address the fast drilling action needed to maintain the required penetration rate.  The steel tooth part was designed with industry-leading hardfacing material on the inner part of the drill bit to mitigate the erosion and loss of cutting structure. The hardfacing material increases the resistance compared with the steel by a factor of up to 10, which allows the bit to be run longer with lower risk of failure.

The new-generation DART drill bit is shown in new and post-run conditions. The outer TCI part addressed the fast drilling action needed and the steel tooth part used hardfacing material on the inner part to mitigate erosion and loss of the cutting structure.

Conclusion

The combined use of the TCI and hardfaced steel tooth cutting structures has shown that the proper combination of these technologies will improve performance in certain types of applications. This application of advanced materials that have been developed in recent years resulted in better performance than possible with the continued use of traditional design concepts.

This combination improved the project’s drilling performance by 54% while reducing the risk of seal failures and losing cones.

Reference:  Les Devine, Burlington Resources Algeria; Martin Ellins, Alasdair Scotchman, Norman May, Baker Hughes OASIS; Sean Connell, Hughes Christensen/Baker Hughes, “Systematic Team Approach to Drilling Optimization Reduces Well Construction Time by 15%, Ghadames Basin, Algeria,” IADC/SPE 74522, 2002 IADC/SPE Drilling Conference, Dallas, Texas, 26-28 February 2002, Dallas, Texas.

Vanguard is a Baker Hughes’ Hughes Christensen trademark.

Ensco won a motion for a preliminary injunction in mid-February against the US Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE), which has been ordered to take action on five of Ensco’s pending drilling permit applications within 30 days and to report its compliance to the court. In granting the motion, US District Court Judge Martin Feldman noted that, under the Outer Continental Shelf Lands Act, the government is under a duty to act by either granting or denying a permit application within a reasonable time. “Not acting at all is not a lawful option,” the ruling stated.

The court also agreed that 30 days is “a common sense marker” of the speed at which applications should be approved or denied – the same as the 30-day time period Congress has mandated in which the BOEMRE must act on exploration plans. Before Macondo, permits were processed in about two weeks. Yet five permits relating to Ensco’s deepwater rigs have been pending from four to nine months – a time frame the judge called “unreasonable, unacceptable and unjustified.”

Senators urge Salazar to streamline permit approvals

A bipartisan group of US Senators, led by Kay Bailey Hutchison (R-Texas) and Mary Landrieu (D-La.), urged the US Department of the Interior (DOI) to streamline the review process for shallow-water and deepwater drilling applications and provide adequate guidance to those seeking new permits.

Sens. Hutchison and Landrieu were joined by Sens. Mark Begich (D-Alaska), Thad Cochran (R-Miss.), John Cornyn (R-Texas), Lisa Murkowski (R-Alaska), Jeff Sessions (R-Ala.), Richard Shelby (R-Ala.), and Roger Wicker (R-Miss.) in introducing a Senate resolution urging timely review of applications.

The resolution also requests that Interior Secretary Ken Salazar provide the industry with a sample application to be used as a template.

Last year, the lawmakers introduced a similar resolution and urged the DOI to provide guidance to industry as to how new requirements can be satisfied. However, to date the department’s new requirements have not been clearly outlined, which has prevented applications from being approved. As a result, at least 12 rigs have left the Gulf of Mexico.

“In spite of the offshore drilling moratoria being lifted, permit delays are causing rigs to sit idle and threatening to send American jobs and tax revenue overseas,” Sen. Hutchison said.

“This de facto shallow-water drilling moratorium is having a painful impact on the Gulf Coast’s economy… I don’t know how much more it will take before this administration understands the harsh consequences of its intransigence,” Sen. Landrieu commented.

IADC was among a number of international organizations invited to participate in the G20 Global Marine Environmental Protection (GMEP) group meeting held in Moscow, Russia, on 17-18 February.The GMEP workgroup was established as a new initiative on offshore oil and gas exploration and development and marine protection as the result of a proposal made by Russia in response to the Montara and Macondo incidents in Australia and the US.

The organizations were invited to make presentations on current activities and initiatives that might contribute to the workgroup’s mandate to exchange information about best practices for preventing and responding to incidents related to offshore oil and gas exploration and development, as well as maritime transportation.

IADC group vice president operations & accreditation Steve Kropla represented the association at the meeting. His presentation primarily focused on continued refinement and growing acceptance of the IADC HSE Case Guidelines; IADC’s work in establishing industry training standards through its accreditation programs such as WellCAP, Rig Pass and Ballast Control & Stability; and IADC’s involvement with numerous international initiatives such as the API/IADC Joint Industry Task Force and the International Association of Oil & Gas Producers Global Industry Response Group.

The GMEP group plans to continue development of a questionnaire on methods of sharing best practices with its members and selected international organizations and international experts, including those from non-G20 countries.  The group will consider responses to the questionnaire, along with a review of international marine environmental regulations of offshore oil and gas exploration, production and transportation to make final recommendations for a mechanism for sharing best practices.

IADC establishes Nigeria Chapter

IADC recently established the Nigeria Chapter based in Lagos. It will bring together members from indigenous and international companies to promote safety, training and environmental stewardship, as well as enhance industry relations with the general public. Dr Lee Hunt, IADC president, remarked: “The Nigeria Chapter will play a vital role in furthering the awareness of local policies and regulations affecting oil and gas drilling, production and service companies operating in the region.” Chapter officers are: chairman, Alex Illah, Transocean; vice chairman, Adeniji Ramoni, Saipem; secretary, Olushola Ismail, Oando Energy Services; and treasurer, Ben Agadagba, Lonestar Drilling.

Unfortunately, reality is a matter of perception, and the perception of mediocrity is out there. The time to change is now.

I had the fortune of hearing industry veteran David Payne of Chevron address a crowd of more than 1,000 people during the GE Oil & Gas Annual Meeting in Italy earlier this year. His message was loud and clear: Industry must visibly raise standards across the board or risk losing its license to operate from the public. “We have to earn that license to operate everyday,” he reminded the audience.

Although much of the change that has taken place in this business since Macondo has been largely driven by regulators and politics, industry does have an opportunity to influence that change. And according to Mr Payne, that opportunity lies not in politics but in engineering.

First, industry must focus on engineering for simplicity. Good engineering doesn’t have to result in something that has never been done before. “The best engineer is the one who can provide the simplest possible solution,” Mr Payne said, citing the inventor of the bicycle as an example of a great engineer.

Second, engineers must pay more attention to the human-machine interface on today’s complex and sophisticated drilling systems. “How many engineers in this room spend the time, after you’ve designed the system, thinking about the person who’s going to operate it? How many engineers in this room spend time thinking about the capacity of the human brain?” Mr Payne asked.

Humans can only multi-task up to a point, beyond which a process or system becomes too complex. “We have yet to design any project in our business that does not rely on a human interface for successful operation… We have to spend as much time on these interfaces as we do on the equipment side,” he urged. In order to have more manageable human-machine interfaces for complex drilling systems, having standard industry practices is a must, he believes.

Establishing such standardization is obviously not an easy task. Unlike the US nuclear submarine industry or the air travel industry or the nuclear power industry – all of which have achieved a high level of standardization within their operations – the drilling industry comprises hundreds or thousands of stakeholders. Two drilling projects in close proximity to each other can be led by the same operator but have equipment with significantly different specs. This kind of complexity makes industrywide standardization challenging, to say the least.

Mr Payne emphasized that he’s not suggesting that our industry follow the templates used by the three aforementioned industries, because none of them would fit. “But that’s not an excuse not to look for a solution,” he said.

Just like in the immediate aftermath of the Macondo blowout, industry found a way to work together and establish the Joint Industry Task Force (JITF). Within a seemingly impossible amount of time, the two work groups within the JITF – one led by Mr Payne and the other by Diamond Offshore’s Moe Plaisance – were able to find immediate opportunities for improvement and make substantive recommendations to the US Department of Interior.

If we don’t want prescriptive rules handed down to us, industry itself must continue to push for more engineering improvements – before regulators and politicians force their perception into our reality.