Drilling technology has not lacked for ground-breaking improvements. Here are some of the game-changing technologies that have altered the drilling landscape.
As the drilling industry addresses the challenges posed by today’s wells, a new approach has been introduced to handle the complexities and difficulties they present. The challenges posed by the need to drill such wells has led to the uptake of managed pressure drilling (MPD) techniques, which use adaptive drilling processes that create a closed loop for the drillpipe and annulus and have become a game changer in drilling the complex and challenging wells of today. MPD allows for early detection of influx or fluid loss and with the inclusion of intelligent control monitoring instrumentation and an integrated choke manifold can provide a degree of automation that can precisely measure and control fluid flow into and out of the well.
First introduced offshore in Asia-Pacific to help overcome drilling issues associated with fractured carbonates, its advantages have since been recognized and adopted rapidly in the last five years due to its applicability to today’s drilling challenges. The automated influx or loss detection and control functionality of MPD make it a game changer, resulting in much smaller anomalies because it provides for a proactive rather than a reactive approach to dealing with drilling problems. MPD is an enabling technology in many areas such as offshore West Africa and Brazil, where formations present major drilling challenges. Weatherford is currently working with operators in these regions to bring the benefits of MPD to their operations to increase safety and help reduce hazard mitigation-related drilling costs. The technique also has been extremely beneficial in recent wells in offshore Trinidad, where the operator was experiencing issues with circulation losses and wellbore stability. Using MPD, the Weatherford system was able to help the operator successfully drill and complete wells, reducing drilling-related nonproductive time (NPT) by as much as 50%. These are but a few examples of the MPD applications worldwide.
MPD has evolved from a niche application system reserved for only extreme environments to being considered a go-to approach for many drilling conditions. The technique can minimize risk, reduce the number of trips, decrease NPT and optimize equivalent mud density.
MPD and its advantages have become so widely prevalent in today’s well plans that operators are beginning to require it to be installed permanently on deepwater drilling vessels. For example, last year due to its experience in drilling presalt formations in deep waters off West Africa, an operator specified that a drillship under construction be equipped with fully automated MPD-ready facilities. Many others are following suit. As water depths of 3,050 m (10,000 ft) become routine, geological complexities such as subsalt formations, rubble zones, fractured carbonate reservoirs and narrow drilling windows become more common, and ultra-HP/HT, pore-pressure and fracture-gradient problems become the norm, so MPD will become the method of choice for tomorrow’s drilling operations. This need is made more relevant and real each day by the tightening of regulatory requirements, the high risk involved and the financial impact of operational failure.
In 1997 the introduction of an effective rotary steerable system (RSS) for directional wells was a step-change for drilling. Directionally drilled wells could now be drilled smoother and faster due to the capabilities and technology advancement that went into the development of the AutoTrak rotary closed-loop steerable system (RCLS). The initial application of this new technology was directed at the high-cost offshore environment. RSS usage increased performance, improved hole quality, changed well design and generated significant value.
The focus on horizontal drilling in unconventional reservoirs created a new need for improved drilling technology. Development of unconventional reservoirs requires exposing as much reservoir as possible to fracture the formation and release the hydrocarbons. These horizontal wells can have lease boundary limitations, so to get maximum horizontal exposure, wells are drilled with a tight radius curve. The buildup rate (BUR) in many unconventional reservoir applications ranges from 10 degrees to 15 degrees per 30 m (100 ft). Previous RSS had a BUR capability that was typically up to 6 degrees per 30 m. Baker Hughes quickly recognized the need for an RSS that could drill higher build rates to deliver or exceed the performance operators had come to expect in conventional directional applications.
The AutoTrak Curve RSS was launched into the market in 2012 as a high build-rate system. From the beginning it was recognized that the drillbit is an integral component to achieve directional objectives, deliver good hole quality and optimize ROP. Key bit design parameters are matched to the operational parameters of the AutoTrak for optimum directional response and performance. The fit-for-purpose polycrystalline diamond compact drillbits from Baker Hughes improve the build-rate capability of the drilling system while maintaining excellent borehole quality. The AutoTrak Curve RSS can also be run with a Baker Hughes Ultra or Ultra X-treme motor for enhanced drilling performance.
Pad drilling is not necessarily a new concept. It has been used in arctic environments for years to minimize the impact of drilling operations on sensitive tundra areas.
But its utility in unconventional drilling has been revolutionary. These resource plays, which require numerous wells to maximize reservoir exposure and production, benefit from the concept. Along with walking rigs, pad drilling has enabled shale operators to improve their drilling efficiency by drilling multiple wells from a single pad.
Prior to the advent of pad drilling, moving a rig from one wellsite to the next required disassembly of the rig, transport and reassembly at the new location. “Today a drilling pad may have five to 10 wells, which are horizontally drilled in different directions [and] spaced fairly close together at the surface,” the U.S. Energy Information Administration notes on its website. “Once one well is drilled, the fully constructed rig can be lifted and moved a few yards over to the next well location using hydraulic walking or skidding systems.”
Walking and skidding rigs are truly one of the biggest drilling innovations to result from the shale gale. In addition to providing drilling efficiency, they diffuse some of the environmental concerns related to shale development since they enable rapid drilling in a confined space. New rig designs allow the rigs to move in multiple directions, and in the case of Patterson UTI’s APEX Walking Rig, the rig can move in a circle with pipe racked back, which provides flexibility for well layout and location constraints.
Drilling fluids are constantly undergoing upgrades as new chemistries are tested. One major step-change has been in the advancement of water-based muds (WBMs) for unconventional plays. WBMs aren’t always the best choice for these plays since the reservoirs tend to have clay content, which swells when coming in contact with water. But LWD imaging tools that aid in reservoir characterization aren’t useful with oil-based muds.
Newpark Drilling Fluids has recently unveiled its Evolution system of WBMs, which overcomes not only issues with clay formations but also HP/HT conditions and deepwater wells. The formulae minimize environmental impact by reducing cuttings and remediation/disposal requirements while increasing ROP and reducing drilling time and cost.
The word “automation” is a hot topic across the spectrum in the oil and gas industry today. It’s probably most applicable in the drilling arena, where things like pipehandling can easily be assigned to an intelligent system and where safety improvements can be quickly realized. But once “iron roughnecks” and other improvements are in place, what’s the next step?
This was the question that the industry initiative to develop a Drilling Systems Automation Roadmap set out to address; this initiative is affiliated with both the International Association of Drilling Contractors and the Society of Petroleum Engineers (SPE). The primary objective was to provide a guideline to the future emergence of drilling systems automation across all aspects of drilling and completions technology. The secondary objective was to inform nonoil and gas industry professionals about the opportunities to support this type of technology development.
The identified technology gaps include:
- Systems architecture, which provides the framework to implement automation in complex systems and takes into consideration the situational awareness of well state, drilling and completion state, automation state, and other situations such as weather;
- Communications, which includes protocol standards and connectivity, with a future that could be defined by the Internet of Things;
- Instrumentation and measurement systems that would provide the necessary input for a fully automated system;
- Drilling machines and equipment that would enable true “factory drilling”;
- Control systems that would be able to understand enough about the drilling process to automatically adjust parameters and provide adaptive levels of human and machine interaction;
- Simulation systems and modeling, in which accurate simulations drive instructions to machines;
- Human systems integration, which addresses the changing role of humans at the wellsite; and
- Certification and standards to identify which industry standards are most applicable to the automation process.
By 2025 the vision is to have well plans updated into an interoperable system that automatically drills the right well in the right location, installs the casing and isolation system according to the drilling plan, completes the well and updates remote operators in real time to changes taking place in the well.
In the offshore rig sector the market’s slowdown in 2014 has changed the dynamics for the main players after a period of several years in which they made hay while the sun shone and invested billions of dollars in high-specification newbuild floating and jackup units.
The ongoing slowdown in terms of utilization rates and day rates has prompted several of them to delay or not exercise options on further newbuild floaters they have with the Far East shipyards—Atwood Oceanics, for example, recently confirmed it was delaying the delivery of two such units.
But with the near-term situation for the jackup market in better shape and industry fundamentals indicating that the mid- to long-term future for high-spec rigs in both shallow, deep and ultradeepwater will remain positive, the rig contractors are not panicking.
With a substantially upgraded high-spec rig fleet estimated to be worth about $16 billion, Transocean, for example, is still in a prime spot to benefit from the continuing increase in deepwater drilling over the coming years.
With deals such as its four-rig arrangement with Shell—expected to generate a 12% initial rate of return over the initial 10-year contracts—the company has a contract backlog reaching nearly $3 billion. Despite the shadow still cast by the Macondo tragedy in the Gulf of Mexico (GoM), which leaves it exposed to settlement payouts and lost revenue totaling an estimated $4 billion, Transocean is fully expected to sail on.
Ultradeepwater day rates are currently at a range of $375,000 to $500,000 due to the current excess rig supply situation, but some units are still coming onto the market now at day rates agreed upon a year or more ago well over the $600,000 mark. Opinions vary as to exactly when the deep and ultradeepwater rig market will start to strengthen again next year, but strengthen it will, especially with a significant number of older floater units nearing the end of their working lives.
Lower spec units at risk
According to Transocean’s latest presentation, it is the older, lower specification floating rigs that are most at risk, with 160 of them more than 30 years old. Customers prefer high-spec rigs, it stated, as they are perceived to be more reliable and have better performance. The jackup market is in the same boat, with 216 units more than 30 years old and with customers actively replacing lower spec rigs with available high-spec alternatives.
According to Noble Drilling, a leveling off of the decline in day rates could occur in first-half 2015, with “early signs of improvement” already occurring, according to Jeffrey Chastain, Noble’s vice president of investor relations, speaking during its most recent analyst presentation.
Chastain outlined the company’s belief that this would occur based on the following:
- Numerous ultradeepwater contract awards during second-quarter 2014;
- GoM, Brazil, and West Africa driving improvement;
- New deepwater discoveries confirming attractiveness of areas;
- Stability of jackup sector through the first half of 2014;
- Early signs of capacity build in some regions;
- New capacity additions of concern—140 rigs on order;
- Standard vs. new capability; and
- Level of speculative orders a medium-term concern.
Another deep- and ultradeepwater-focused player, Pacific Drilling, chose recently in its own investor presentation to highlight some of what it sees as key industry trends impacting the offshore drilling sector:
- Challenges of remote drilling sites;
- Drilling deeper and with longer offsets;
- Greater drilling efficiency to reduce total well costs;
- Advances in well construction techniques, e.g. intelligent completions;
- More demanding downhole environments, e.g. HP/HT drilling;
- Increasingly demanding regulatory climate; and
- Increased client focus on safety.
It also pointed out that 90% of high‐spec floaters actually operate in less than 2,286 m (7,500 ft) water depth on average, which highlights the push by operators to use the units that they feel will give them the best drilling efficiency.
So just what are the latest high-spec units actually capable of? One unit that began operations during 2014 is a great example of what is considered to be a game-changing rig.
With conventional drilling in many cases not allowing economic completion of deep wells, dual-gradient drilling (DGD) is a technology whose time has come after decades of industry R&D. Taking advantage of the long riser in the water column as a tool for managed-pressure drilling (MPD), it has now emerged as a highly desirable way of implementing MPD in deepwater wells.
This year saw Pacific Drilling’s Pacific Sharav delivered and start drilling for Chevron in the GoM, carrying out operations in the Keathley Canyon area. The drillship, built to Chevron’s own exacting specifications, will work under a five-year, $558,000/d contract for the operator. The drillship is an upgraded dual load-path Samsung 12000 design, a dynamically positioned unit modified to accept a DGD system. It is able to operate in moderate environments in water depths of up to 3,658 m (12,000 ft), drilling wells to a total depth of 12,192 m (40,000 ft).
Chevron’s vice president of deepwater exploration and projects in North America, Steve Thurston, stated in a press release earlier this year that Chevron worked with Pacific Drilling “from the very early stages in the design and specifications of the drillship capabilities to ensure the right fit with our drilling program and needs, building on lessons learned and capitalizing on a long-standing business relationship.”
The drillship and its sister vessels are described by Pacific as featuring the most advanced drilling technology in the offshore industry, including dual load-path capability and the latest in DGD technology. The vessel and the technology onboard is the culmination of more than 15 years of R&D.
Dual-gradient ‘prime time’
Robert Ziegler, head of Wells & Production Technology at Petronas, agrees that this technology’s time is right now. In his opinion, DGD “is ready for prime time.”
Presenting at the recent SPE Annual Technology Conference & Exhibition in Amsterdam, he pointed out that while plenty of innovation has been achieved in the area of pipe and riser handling on the latest sixth-generation rigs, the actual drilling process has not changed a great deal compared to earlier rig generations.
Among the leading deepwater drilling operators, the need for MPD in deepwater is becoming more and more apparent due to the wells that need to be drilled now and into the future, he said. With DGD taking advantage of the long riser in the water column to implement MPD in deepwater, Ziegler went on to highlight the ability to retrofit DGD systems using electrically powered mid-level riser pumping technology to existing deepwater rigs.
This is not just a concept, however—one such retrofit (on the Scarabeo 9 semisubmersible) has been performed and field-proven on three commercial ultradeepwater exploration wells in the U.S. GoM.
The pumped riser technology extends the benefits of riserless drilling by taking away mud overbalance at the mudline in deepwater drilling operations, according to Ziegler.
An innovative solution for smaller modular offshore rigs also progressed during 2014, with engineering house William Jacob Management (WJM) tasked by Pemex to bring down rig deployment costs and increase speed to production.
The company was contracted in 2012 to provide fast-track engineering and design services for two platform drilling rigs to eventually be used for operations on the heavy oil Ayatsil Field in the Bay of Campeche offshore Mexico. WJM successfully completed the design work for the two 3,000-hp modular offshore rigs for Pemex in the second quarter of this year.
The platforms have an eight-leg jacket and deck and weigh about 11,650 tonnes for installation in 115 m (377 ft) of water. The company says its modular offshore rig facility (MORF) design is the first of its kind in size and configuration.
The rig’s individual modules can function like a set of interlocking building blocks and be lifted in place by “leapfrog” cranes, which enables it to be configured for drilling and integrated production below.
The unit design has two main modules: the drilling equipment set (DES) and the drilling support module (DSM). The DES has the capacity to access 15 wells arranged in a 3-by-5 matrix and is capable of drilling wells up to 7,620 m (25,000 ft). The DSM is equipped with a pair of rig cranes that streamline installation. Thanks to their compact size, the modules can be delivered using the client’s service fleet and then assembled using a combination of crane systems. The blocks containing the cranes are installed using the leapfrog crane package.
Once the rig cranes are operational, the installation is then completed using the rig’s own cranes, effectively eliminating the need to contract a lift barge.
Onshore completions set records
Advances in technology have shaped the shale revolution.
Rhonda Duey, Executive Editor
Horizontal drilling and hydraulic fracturing are not new technologies. But the combination of the two has kicked off one of the biggest revolutions in oilfield history—development of unconventional reservoirs. Unconventional reservoirs come in many shapes and sizes, but they mostly share the same characteristic of extremely tight formations that will not produce without the induction of fractures. In just a few years hydraulic fracturing has seen enormous strides.
From just a few frack stages a decade ago, companies are now experimenting with “advanced completions” that involve massive amounts of proppant and frack fluid, numerous stages and longer laterals. NCS Energy Services just set completion records of 94 stages and 104 stages in two wells in the Bakken in a multistage coiled tubing completion.
The technology also is expanding, with plug-and-perf operations being performed in cemented liners while ball-actuated sliding sleeves are often the technology of choice in openhole completions. Recent advances in the latter include degradable balls that eliminate problems with balls deforming during the stimulation process.
Proppants also have undergone some changes, though in many of the shale plays operators still use sand rather than ceramic proppants.
Most recently, completions are getting attention as operators attempt to maximize production. Weatherford, for instance, has introduced FracAdvisor, an integrated solution that provides optimized fracture design by calculating frackability along a horizontal or vertical wellbore, field or basin for enhanced telemetry perspectives and a more profitable fracture operation.
The new service analyzes the different attributes gleaned from the logging tools and places them side by side (or above and below, in the case of a horizontal section). At the bottom of the screen the tool shows the typical geometric perf design compared to what it considers to be the optimal design based on the attributes that have been identified.
“We can move where and how long the stages are to maximize the completion using the information to improve fracking like rock with like rock within a stage,” said Jim Rangel, manager of petroleum consulting at Weatherford. “That’s what this tool recommends.”
Bits positioned to provide step-change in drilling performance in difficult formations
Contributed by Schlumberger
Smith Bits, a Schlumberger company, recently launched StingBlade conical diamond element bits. StingBlade bits have Stinger conical diamond elements optimally placed across the bit face, which are innovative polycrystalline diamond compact (PDC) cutting elements with a conical shape and thicker diamond layer. The conical shape enacts a highly concentrated point load on the formation, fracturing high compressive-strength rocks more efficiently while also generating less torque and vibrations than a conventional flat PDC cutter. The thicker diamond layer enhances impact strength and wear resistance. When placed across the bit face, Stinger elements enable StingBlade bits to yield a step-change in drilling performance over existing roller cone and PDC bit technologies, including significantly improved footage and ROP, higher build rates with better toolface control in directional applications, bottomhole assembly shock and vibration mitigation from enhanced bit stability, and larger cuttings for more accurate surface formation evaluation at the rig site.
Stinger elements are placed across the bit face of StingBlade bits based on the operator’s application requirements and drilling performance objectives. StingBlade bits can have Stinger elements used in conjunction with conventional PDC cutters, or a StingBlade bit may contain only Stinger elements. Due to the enhanced impact strength of Stinger elements, they may be placed in areas where impact damage is observed on baseline bits run in the same application. Regardless of the application, all Stinger elements on StingBlade bits are oriented to do a significant amount of work on the cutting structure, typically being on profile and with their own unique path to fracture formations.
An operator planned to drill a 12 ¼-in vertical section through the challenging Dampier, Heywood, Baudin Marl and Wollaston formations in the Browse Basin offshore Australia. These formations are composed of interbedded hard limestones and chert with high compressive strengths, which induce heavy damage to conventional PDC bits. This damage can slow ROP and requires the operator to pull bits prematurely, requiring additional time to drill the section.
The operator used a StingBlade bit to drill 1,516 m (4,974 ft) at 11 m/hr (36 ft/hr), equaling 97% more footage than the best run in the same section of an offset well while also achieving a 57% improvement in ROP. A second StingBlade bit was used to drill the remaining section to total depth at an average ROP of 16 m/hr (52 ft/hr). The two StingBlade bits enabled the operator to save more than five days of drilling time in the section.
There have been more than 250 runs in 14 different countries, both onshore and offshore, in conventional and unconventional applications in North, Central and South America; the North Sea and Europe; and Africa, the Middle East, Russia, Southeast Asia and Australia. An average of all runs has shown a 55% footage improvement with a corresponding 30% ROP improvement. In addition, many StingBlade bits have achieved directional objectives, receiving positive feedback from directional drillers and operators with respect to steerability and toolface control.
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