By Katie Mazerov, contributing editor

Schlumberger’s FUTUR active set-cement technology self-heals from the time it is placed until the end of the well’s operational life and into abandonment. The image illustrates the chemical reaction that the cement undergoes during setting and when there is an invasion of hydrocarbons. FUTUR reacts with seeping hydrocarbons to create an impermeable barrier.

Hydrocarbon production is a risky business, and nowhere is this more evident than in the deepest, darkest waters on the planet, where some of the brightest prospects for the future lie miles beneath the surface. High pressures and temperatures, extended laterals and unstable reservoirs are among critical challenges operators face in this vast frontier that includes the Gulf of Mexico (GOM) and West Africa. With that in mind, an industrywide effort has been under way to minimize risk and ensure that the necessary systems and processes are in place to make deepwater and ultra-deepwater development safe and efficient. A key focus of the effort involves well cementing, everything from design to testing to placement.

Using cement as a viable barrier to protect the wellbore from dangerous influxes of water or gas looms as one of the biggest issues facing the industry as it looks ahead 20 years and beyond. Operators, major service companies, academics, regulators and trade associations are placing significant focus on every aspect of the cementing process, working to enhance current designs, standards and protocols, and engaging in out-of-the-box thinking to develop smarter and more durable methods that will deliver a high degree of integrity in the increasingly complex wells of the future.

One of the key players in this endeavor is the Research Partnership to Secure Energy for America (RPSEA), a nonprofit corporation established by the US Department of Energy that is providing financial incentives for a number of ambitious deepwater cementing research projects ranging from radio frequency identification (RFID) to intelligent casing, and even a study on human error. “We are looking at this issue from a holistic viewpoint and coordinating knowledge-sharing among the various stakeholders,” said James Pappas, vice president of RPSEA’s Ultra-Deepwater Program. “For example, we are taking academic research in nanomaterials and partnering with companies that can turn science into engineering solutions.”

However, much of the push is coming from the oil and gas companies that are leading industry into the deepwater fields, where safe extraction of the huge oil and gas resources is paramount. Well cementing is among the top priorities.

“Cementing is one of the very important elements that well integrity experts take into account in their evaluation of risk and their assessment of wells that have been delivered,” said Dan Mueller, cementing specialist, global drilling engineering for ConocoPhillips. “It is safe to say that the Montara and Macondo incidents forever changed the well-cementing landscape. How we model, design, test, place and verify cement properties are all considerably different than they were pre-2010.” Montara was an uncontrolled discharge of oil and gas off the coast of Western Australia in 2009.

Today’s deeper wells tend to have bigger wellbores and therefore larger casings, more casing strings and tighter annuluses that must be cemented. Schlumberger has management of change protocols in place to address issues such as temperature variations and last-minute well construction changes that can impact the viability of the cement.

Collaborative effort

An important part of the undertaking has been the collaboration between the industry’s cementing community and API to evaluate and update current well cementing standards. In December 2010, API’s Well Cementing Subcommittee (SC-10) published what is now API Standard 65-2, which addresses the issue of isolating and cementing potential flow zones during well construction.

“This is a landmark document for the well cementing industry in that it is both a recommended practice and it establishes requirements,” Mr Mueller said. “It signifies the cementing community’s attempt to take into account some of the lessons learned from Macondo and take steps to limit exposure in these areas going forward.”

The standard was included in the US Federal Register in August 2012 and is now part of the cementing requirements related to permitting in the GOM under the Bureau of Safety and Environmental Enforcement (BSEE). Standards addressing deepwater cement testing will be published this year, and a standard regarding foamed cement preparation and testing is being revised and expected to be released this year. Foamed cement is designed to address shallow-water flow.

The focus is on testing and evaluating cement under conditions that are as realistic as possible. “We are writing our testing procedures and documents in a fashion so we can, as best as possible, simulate the placement and thermal history of the conditions the cement will be exposed to during the placement process and using that as a basis for evaluation,” he continued. “The testing requirements are now higher, and requirements for simulating placement history are there. Since we depend so much on testing results to move our judgments in one direction or another, it is imperative that the tests be as realistic as possible.” The procedures are being included in recommended practices so service companies can conduct testing under uniform conditions.

Pressure and, especially, temperature also are important considerations in well cementing. “We have a reasonable ability to predict the pressure state of the system. But since temperature is the single most critical factor influencing the behavior of a well cement, we are being very diligent in our thermal modeling,” Mr Mueller said. “We will use multiple thermal models in many cases to ensure temperature is being properly taken into account.”

Oil and gas production companies will be incorporating the new procedures and regulations into their operations while already engaging in more in-depth vetting of cementing proposals and recommendations. Design elements that are being taken into special account include casing centralization, equivalent circulating density (ECD) management and mud displacement efficiencies, which all lead to establishing a quality cement sheath, Mr Mueller said.

“This very necessary work has changed the way we think about cementing,” he added. “As an industry, we have looked at our systems and processes and found new vigor to get these standards in place to avoid any incidents going forward. There are many ongoing joint industry projects and collaborative efforts looking at deepwater technologies to make these operations proceed in a streamlined way. Deepwater is an important part of many operators’ portfolios, and over the past 12 months, we’ve seen a substantial ramp-up in activity in the sector.”

Collaborative industry effort leads push to enhance deepwater cement standards

By Katie Mazerov, contributing editor

In keeping with its historical mission to develop standards and recommended practices (RP) in a collaborative fashion that ensures all stakeholders and interests are represented, API has been at the center of a rigorous, industrywide effort over the past three years to publish a number of offshore safety measures, many of them focused on the critical aspects of deepwater cementing.

“This work, involving all sectors of the oil and gas industry, began with four joint industry task forces that came together in a very short time after Macondo to produce recommendations that the White House used as a basis for its response to the event,” said David Miller, API director of standards. “A number of key recommendations have come out of this coalition, including the Center for Offshore Safety.” Established in 2011, the center promotes and adopts standards of excellence to ensure continuous improvement in safety and offshore operational integrity.

The initial focus of the industry’s efforts was API Standard 65-2, addressing isolating and cementing potential flow zones during well construction. “Following Macondo, an industry group got together and immediately started revisions on API 65-2, taking lessons learned from the incident and really enhancing the document in terms of the requirements needed for offshore safety,” said senior standards associate Shail Ghaey, who is the staff liaison for API’s Well Cementing Subcommittee.

Since then, the subcommittee has engaged in work to revise and develop other cementing-related documents, including API 65-1, now referred to as API RP 65, which addresses cementing shallow-water flow zones in deepwater wells. “Considerations when cementing in the upper section of the well are slightly different than they are for sections farther down the wellbore,” Ms Ghaey explained. “Cement is applied in shallow zones to isolate any potential flow zone from water or gas.”

Cement testing

Another series of documents specifically addresses the testing of well cement. Included in the series are RP 10B-2, RP 10B-3 and RP 10B-4 – testing in labs under simulated in-situ conditions along with general atmospheric and temperature-related factors.

Later this year, API also will publish RP 96, which provides deepwater well design considerations. “This document will address the different kinds of barriers, including cement and mechanical barriers, that can be used when designing these deepwater wells,” Mr Miller said. “This will be a fairly significant step forward for the industry in deepwater applications.”

Modern cementing equipment is highly automated and process-controlled to meet rigorous standards for quality control.

A viable barrier

Much of the ongoing research centers on redefining what is required for cement to provide a viable barrier. “If we want cement to be a barrier, we can’t just go in and cement a zone, we need to define the criteria for it to be successful,” said Ragheb Dajani, senior drilling engineering advisor for Hess Corp. “We need to define how far up in the zone we need to cement and understand if and when a zone has been successfully cemented in terms of placement. For example, we’ve agreed that 50-psi compressive strength is the minimum standard for calling cement a viable barrier. Previously, that was not defined.”

A lot of energy is being put around the operational aspect of ensuring that the practical realities reflect the theory. “If we’re dealing with 100 bbls of cement and 1,000 bbls of placement, for example, we have to do a lot of work to make sure the cement is placed effectively,” Mr Dajani said.

Other issues being addressed include new government stipulations that operators must run a worst-case discharge tie-back, which necessitates that an extra casing be run. Due to wellbore dimensions, that second casing creates an ultra-narrow annulus that must be cemented. “The pressures are enormous, and placement is extremely critical to prevent casing collapse,” he noted. “This is very challenging and new to the industry; only four jobs have been done since the regulation was put in place.”

Difficulties also can occur in situations of low-salt regressions, where lower pressures occur after exiting the salts, creating a drop in pressure and necessitating that mud and cementing weights be changed. “A lot of times that is an issue with lost circulation, and we know that lost circulation is a challenging issue if we can’t place the cement where it needs to be,” he said.

Finally, in the top-hole section, where the surface casing is placed, shallow flow hazards can be problematic, for example, when silty soil contains a high-pressure section. If there is not enough hydrostatic pressure to hold it in place, the formation will start flowing – meaning the wellhead and blowout preventer (BOP) won’t have any soil support. “Choosing the right technology, such as a foamed system, and getting the correct volumes and properties to mitigate that scenario is required, and we need to ensure that the methods we know work are being deployed.”

Hess has implemented the new standards and recommended practices internally and will apply them to the company’s operations in the GOM, including on two of its contracted deepwater rigs and a program that will be launched this year.

“We feel the industry is where it needs to be from a best practices and standards perspective, and we are working on bridging the gap between what has been put on paper and what needs to be implemented operationally in the field,” Mr Dajani said. “I believe the biggest gap is getting the young engineers trained quickly, especially field training and experience, so they can truly understand the intricacies of what happens on a drilling rig.”

Long-term viability 

Schlumberger’s FlexSTONE cement enables set cement to conform to changes during a well’s drilling, production and abandonment phases.

The long-term viability of cement as a barrier is also very much on the agenda. “One of the primary challenges we have as an industry is not just in providing the correct recipe for cement materials to do a proper job of isolating and protecting the wellbore but in knowing what the long-term stability will be,” said RPSEA’s Mr Pappas. “We are searching for ways to gain more confidence that we have the necessary long-term protection while meeting all of our social responsibilities.”

To that end, laboratory testing is tracking the behavior of cement materials, mimicking conditions seen in deepwater environments and subjecting cement to cyclic heating, cooling and other stresses to determine the long-term effects. The history on cement modeling in land environments is being used to extrapolate what can be expected to happen in deepwater.

RPSEA is focusing on niche ideas that aren’t being addressed by anyone else, and on identified weaknesses, including hole-cleaning while drilling and the subsequent cementing process, and annular pressure build-up. One proposal is looking at new methods of detecting cement bonding with both the formation and the pipe. “The cement bond tools do a pretty good job of providing a cement-to-pipe bond but not as good a job at visualizing cement bonding to the rock,” Mr Pappas said.  “We review ideas and proposals like these and determine which ones are going to move forward and then monitor the progress.”

Researchers at the University of Oklahoma are working to develop a telemetry system that, powered by tiny batteries, can transfer information about the cement and the flow of production fluids up the pipe. The University of Houston and partners are researching the possibility of placing small RFID chips in drilling fluids to provide a better understanding of hole quality, which is critical for a good cement bond, and even placing the chips in the cement itself.

“We are hoping these tools can work in the liquid stage but also after the cement hardens so we can gain information on the stresses, strains and changes of the cement over time, after the well has been perforated and frac-packed,” Mr Pappas said.  “We can use these devices to learn and also theoretically read and measure changes in real time, which would be a leap over what is available now.”

To address the problem of ECD and pressure and temperature changes in deepwater reservoirs, RPSEA has contracted with engineering firm CSI Technologies and partners to develop a novel system of pumping cement down the backside of the well, with tools to lock the cement in place at the bottom of the casing. “The very small gap between the reservoir pressure and the fracture gradient, or breakdown pressure, can potentially crack the rock, causing lost circulation, particularly in subsalt wells,” he explained. “Tremendous pressures occur when pumping cement down the inside of the casing string and circulating it around the back.”

Baker Hughes has developed a matrix that is reviewed for all primary and remedial cementing operations to assess risk, mitigation options and consequences for the entire well, pre-spud. The numbers across the top denote the casing size rounded down (i.e., 13 5/8-in. casing is noted 13,
9 5/8-in. is 9, etc). “Y” or “N” means “Yes” or “No” as it applies to the risk identified in each row. Shallow-water flow risk, for example, applies to the first couple of strings in the well; thus, the larger numbers might have a “Y” but an “N” for the rest of the strings where the risk does not apply.

The reverse circulation project will include developing tools to accurately measure friction losses on the backside. The method has been done in land wells where the well is not cemented all the way to the top or when running a small coiled-tubing unit between the casing and the hole, he noted.

Another initiative involves studying human error in the drilling process, including during cementing. “We want to know what makes people tick and what scares them from shutting systems down when they see something is wrong,” Mr Pappas said. The project includes the creation of a database of near-misses in the GOM to try and model human behavior.

Meanwhile, in an effort to ensure safety and minimize human error, service companies have put in place their own risk management procedures regarding deepwater cementing while continuing to develop new technologies and enhance existing services.

Schlumberger has had management of change protocols in place to address issues such as annular casing pressure, temperature variations and last-minute well construction changes that can impact the viability of the cement. This is in line with industry’s overall push to focus on assurance, verification and documentation as it strives for efficiency. “In the offshore sector, dayrates and other costs are quite high, so there is enormous pressure to be efficient every step of the way,” said Gunnar DeBruijn, well integrity domain manager, North America, for Schlumberger Well Services. “But we also need to recognize how efficiencies impact the overall drilling operation and, ultimately, the cement job.”

In that regard, prior to execution of the cement job, well construction documents are reviewed by operators, drilling contractors and third-party providers of services such as cement, to ensure the cement will provide a continuous barrier. “Flawless execution is the key to a good cement job,” he said. Data collected from both the wellbore and the cement unit is important for documentation, and the interpretation of the data must be done for verification to meet industry standards and regulatory requirements.

“As we get into deeper wells, we tend to have bigger wellbores to deliver production, so we have larger casings, more casing strings and tighter annuluses we have to cement,” he continued. “Often, we’re drilling across large salt intervals so we have to manage an ever-tightening pressure window, meaning we have to be very precise in managing the pressure. In wellbores that are very challenging, we have to deliver the rheology and density as we design the cement.”

Data on temperature variation is especially critical. “In deepwater, we have cold temperatures at the mud line and very hot temperatures at the bottom of the well, so we have to tailor the top section of cement one way and the bottom another way,” he explained. “Most other segments of the industry only require a maximum temperature to understand if tools are installed correctly, but cement must be set to a specific temperature environment. For example, for the first casing string, the cement needs to provide structural support and also set quickly to act as a barrier to prevent shallow flow.”

This cement cube illustrates the capabilities of Baker Hughes’ new self-sealing cement technology for a 0.003-in. width fracture that was induced from entry to exit point under pressure.

To overcome challenges such conditions present for standard Portland cement, Schlumberger has developed high-performance cement systems and additives to ensure viability and long-term durability. The EverCRETE is a CO₂-resistant cement, and the FUTUR, active set-cement technology, is a self-healing cement system that works after the cement has set, from the time it is placed until the end of a well’s operational life.

“As we do more design work on these wells, we also assess the stresses they go through and look at implementing cement systems such as the FlexSTONE advanced flexible cement technology that provides zonal isolation by enabling set cement to conform to the changes that occur during the drilling, production and abandonment phases of a well,” Mr DeBruijn said.

For deepwater, the DeepCRETE deepwater cementing solution isolates the formation and develops compressive strength faster than Portland cement. When combined with Schlumberger’s gas migration technology, the solution provides shallow flow control. The DeepCEM deepwater cementing solution can perform in environments as low as 32°F.

Schlumberger also has added more oversight to its processes, reviewing every deepwater cement program worldwide. “If we see risks we shouldn’t take in an operation, we inform the operator and other service providers so the risk can be mitigated,” Mr DeBruijn noted. “Oversight also helps with continuous improvement and transfer of knowledge from one operator to another.”

Baker Hughes has developed a matrix that is reviewed for all primary and remedial cementing operations to assess risk, mitigation options and consequences, which are then discussed in a peer review setting. “One of the biggest changes the industry has seen the past few years is increased awareness of risks, with consideration of risk-based decisions and contingency planning,” said Joe Shine, cementing product line manager.  “Some of the more important issues we’re looking at as we get into deepwater cementing are top-hole, or riserless, sections and subsalt environments, both of which present unique challenges. Often there are unknowns that are not accounted for in the pre-job planning phases that require us to proactively prepare prior to starting the well. That is where we build in the risk contingencies.”

From a technology standpoint, engineers at Baker Hughes are refocusing their efforts on cement design and methodology, examining what has been done in the past and where they believe the industry will be in five years. For example, the company is working on a new foamed cement system, which adds nitrogen or other compressed gas to the cement matrix to give it the necessary properties to best meet well objectives. The new system is expected to have significant applications in the GOM and other sedimentary basins around the world.

Foamed cement specifically addresses shallow hazards by counteracting  the hydrostatic pressure loss that initiates water or gas flow, maintains internal pressure and prevents volume loss as the cement transitions between the liquid and set states.  “We’re not only looking at the type of cement but ways to better technologically deliver the product at the wellsite,” Mr Shine said.

Baker Hughes also has developed a self-sealing cement that has the capability to seal a micro-annulus or fissure within the cement sheath itself. Another product being advanced is a synthetic cement, commonly known as a non-Portland cement alternative, to provide better wellbore integrity solutions. “Processes such as temperature and pressure changes affect cement, so with this alternative we’re trying to develop a product that will provide more durability for the life of the well,” he explained.

Mr Shine recently presented a paper, SPE/IADC 163446, on Baker Hughes’ new cement simulator, which uses software to design cement placement, at the SPE/IADC Drilling Conference and Exhibition, 5-7 March in Amsterdam. “We now have advanced modeling software that can account for non-aqueous fluid compressibility behavior and losses before we actually provide the cementing service,” he said.

Going forward, he sees limitations in the availability of specialized bottomhole testing equipment for deeper, hotter and more unknown conditions. “Attaining the temperatures and/or pressures required in these wells is not always achievable,” he said. “Testing is limited to a point, presenting a technology gap that many in the industry have determined needs to be addressed.

“As service companies strive to bridge such technology gaps in the critical deepwater cementing sector, we are taking a holistic approach, looking at the overall delivery of services, including the pre-job, execution and post-job stages, at the well,” he continued. “Everything is more comprehensive, and there is more quality assurance driving the process.”

By Katie Mazerov, contributing editor

VAM Drilling’s Hydroclean products
provide hydro-mechanical hole-cleaning solutions integrated into the drill pipe. Efficient hole-cleaning results in less nonproductive time.

Just as wells have become longer and more complex, drill pipe is not what it used to be. Improved steel grades and connections for conventional pipe, advanced materials for extreme environments, wired drill pipe that can deliver significant amounts of data, and durable hardbanding systems that extend pipe life while protecting casing are all on the table.

“Extended-reach drilling (ERD) has already achieved remarkable milestones with wells like ExxonMobil’s OP-11 with a measured depth of 40,502 ft and a horizontal departure of 37,648 ft,” said Mazhar Mahmood, global product line manager – drill  pipe for VAM Drilling, a company in the Vallourec Group.

“The industry is currently planning ultra-deepwater wells with a total depth of up to 50,000 ft, so we will start to see the drilling envelope move to deeper and longer horizontals. Drill pipe selection becomes very important as well designs become increasingly complex, since it affects critical parameters such as equivalent circulating density (ECD) management, hole cleaning, casing wear, torque and drag and very high tension loads at total depth. Drill pipe solutions will vary with each situation.”

Operators and drilling contractors require safe, reliable and efficient drill string solutions that are cost-effective through the product lifecycle. “Most drill string products on the market may meet basic requirements for non-challenging and generalized situations, but they may not be the optimum solution in terms of both performance and lifecycle costs,“ Mr Mahmood maintains. “Today, it’s more a question of if the drill string is not only optimized but also offers an efficient and user-friendly high-performance connection that has a lower repair rate and lower repair costs.”

For the near term, material benefits and new designs of any major breakthroughs will have to take into consideration additional cost to the customer, Mr Mahmood believes. “In terms of mechanical properties like torque, tension and hydraulic properties, we already have enough torque to drill what we need. For drill pipe connections, the focus is on how to generate more operational efficiencies and reduce repair costs.

“The US unconventional market is quite unique in terms of drill pipe lifecycle costs; drilling practices in most cases render the life of drill pipe significantly reduced due to premature midsection tube wear, handling damage to double-shoulder connections, excessive repair rates and associated high repair costs,” he continued.

“Vallourec understands that the unconventional shale market requires products that will deliver greater efficiency and cost savings and that can address issues such as midsection tube wear. Products have to adapt.”

For a shale well in Poland, the company designed a custom solution to allow the operator to drill and core using the same drill string, eliminating the time and cost of making multiple trips to change the string. The proposed operation will use a custom high-performance, 5-in. drill pipe for coring with a minimum drift of 4 in. in the vertical section of the well.

NOV has embraced wired pipe technology to enable drilling automation. The technology prevents delays in data transmission that can prevent an automated closed-loop control system from working. At a data transmission speed of 57,600 bits/sec, wired pipe can remove that barrier to automated drilling.

Focus on offshore market

In the next three to five years, the growing offshore market will also be a major focal point for drill pipe innovations. In particular, advances in risers, landing strings and other essential products are seen as the next frontier. “As the drilling envelope gets deeper, landing strings will need to be as light as possible to carry more payloads,” Mr Mahmood said.

Some customers are looking at using a single string that can perform the dual functions of drilling and landing the casings. There also will be special designs for drill pipe risers in special environments like Brazil because of the water depths combined with high sulfide stress cracking (SSC) resistance.

For extreme environments, Vallourec sees demand for higher-strength steel grades. “The newer grades have specific steel chemistries and heat treatments that enable deeper or farther drilling without making the drill string heavier, hence increasing the rig capabilities,” he explained. The company also anticipates new challenges associated with sour field exploration and development, which requires new highly engineered drill string solutions to increase the safety margin related to SSC failure risks, especially in the upset and welded zones of the drill pipe.

Even though the Arctic drilling market is not yet mainstream because of regulatory, environmental and equipment concerns and the narrow weather window, VAM Drilling has introduced proprietary steel grades for Arctic drilling that combine high strength with high toughness guaranteed at the extreme low temperature of -60°C (-76°F). “The region holds vast potential for meeting future energy needs,” Mr Mahmood pointed out.

Additionally, Vallourec is offering hydro-mechanical hole-cleaning solutions integrated into drill pipe. The existing VAM Drilling Hydroclean and the latest-generation Hydroclean Drill Pipe have helped achieve rig time savings through efficient hole cleaning, resulting in less nonproductive time, he continued.

NOV IntelliServ’s inductive couple IntelliCoil is embedded in the ends of each piece of drill pipe to accomplish data transmission across tool joints.

A significant drill pipe innovation gaining traction in the sector is wired drill pipe, thanks to a push from a growing body of operators who believe in the value of the technology, said David Pixton, senior fellow with NOV IntelliServ, a joint venture of National Oilwell Varco (NOV) and Schlumberger that provides high-speed, high-volume and high-definition downhole data via wired drill pipe.

Since wired drill pipe emerged in 2005, early apprehension has given way to increased interest and industry acceptance of what the technology can achieve in a variety of land and offshore applications. Unlike conventional data-transmission tools located at the end of a drill string, wired drill pipe comprises the entire drill string, meaning everything in the string is wired between data-generating (or data-consuming) tools in the well and computerized applications at the surface that interact with the downhole tools. The technology offers a data transmission rate of 57,600 bits/sec, magnitudes faster than mud pulse, and offers the advantage of looking at points all along the drill string, in addition to the bottomhole assembly (BHA).

“Wired drill pipe provides the ability to attain both process and formation data in real time, which offers greater wellbore visibility and better control of the drilling process,” Mr Pixton said. “Operators can put sensors anywhere along the drill string to gain a much more complete picture and a more competent model of what is going on downhole. This reduces guesswork and waiting, resulting in higher-quality and more timely decision-making. Applications that people thought were still out in the future are being done to some extent today.”

NOV, for example, has embraced the technology to enable drilling automation. “What kills any automated closed-loop control system is delay; however, the type of information we can provide and the time frame in which we can provide it removes such concerns. This is a key factor as industry starts walking down the road of automated drilling.”

Wired drill pipe can be particularly beneficial in situations where there is a need to communicate directly with the BHA. In some cases, wired drill pipe provides the only means of doing this. “Some customers operate in the realm where mud pulse technology doesn’t work because they need to monitor conditions continually even when there is no flow, or they are working with aerated muds or other fluids not compatible with mud pulse,” Mr Pixton explained.  In one instance, an operator was losing drilling fluid, but the mud pulser wouldn’t allow aggressive use of lost-circulation material. With wired drill pipe, which functions independent of the fluid, the customer was able to reduce mud losses.

Another application is in environments where high-resolution data is critical and can’t be delivered in real time by conventional downhole tools. For example, sometimes an extremely tight pressure window requires high-quality real-time monitoring in order for the well to be drilled. “With mud pulse technology, an operator either has to wait a long time to get high resolution, or play a guessing game by trying to interpret a fuzzy picture,” Mr Pixton said.

The necessity for high-speed, high resolution data for better well placement is an industry driver. “This technology can deliver timely and high-resolution feedback of positional and other logging data that can help steer the well very precisely to reduce tortuosity, stay within the formation or create the desired wellbore profile in that formation,” he explained. “Alternatives are to log the well or obtain information when not drilling, which is sometimes not possible because of the need for timeliness of the information. It is also costly because it requires a trip and wireline run.

An NOV Tuboscope technician inspects drill pipe on a rig site; the service is typically performed after every other well.

“Finally, when customers are in a drilling situation where downhole conditions are changing due to cuttings build-up, an incompetent  formation, or geologic movement of the well, they need very timely data,” Mr Pixton continued.

The IntelliServ technology is now available under a different delivery arrangement that enables more cost-effective access to operators globally. Wired drill pipe will be available through drill pipe rental companies or rig contractors in place of conventional drill pipe. The electronic components required for high-speed data transmission on a wired drill string will be provided through MWD companies, enabling them to offer an enhanced version of their current telemetry services.

IntelliServ will enable and facilitate these measurement companies to develop their measurement tools for along the drill string, in addition to BHA-based tools. This may include the adaptation of existing measurement tools, such as vibration or ECD measurement tools, to a design that can be distributed along the drill string, or the development of entirely new sensors or measurements.  Even existing tools, such as circulating subs or underreamers, may be enhanced by enabling actuation by commands sent from surface.

“Service companies are starting to understand the value that more measurements can deliver in wellbore modeling, dispelling fears of too much data,” he said. “We’re finding that the amount of data generated by our telemetry system actually helps enhance models and ultimately provides a faster and more reliable drilling process.”

ERD also has pushed demand for hardbanding, a specialized consumable applied to the external surface of drill pipe tool joints to protect against abrasive wear and thus extend the life of the pipe. Hardbanding is typically specified and applied as part of the drill pipe manufacturing process and, depending on factors such as abrasiveness of a particular formation and the performance quality of the hardbanding, eventually wears down and needs to be re-applied. Reapplication occurs either in the field or at a nearby facility by a certified applicator. Throughout the life of the drill string, hardbanding may be applied a number of times.

The company launched its casing-friendly TCS 8000 hardbanding (left) in 1998 in response to an increase in extended-reach drilling. The newer, TCS Titanium products (right) was designed for more challenging well environments.

NOV Tuboscope’s offering of hardbanding materials is part of a total package of reclamation, inspection and repair services for used drill pipe. The company has 80 mobile hardband units in all major basins, including the Bakken and Eagle Ford plays, said Mark Juckett, hardbanding product line manager. Drill pipe is typically inspected after every other well, while hardbanding is reapplied as needed pending evaluation, he said.

“With the advent of ERD, requiring long sections of casing, in the 1990s, hardbanding went through a transformation, with the need shifting from protecting the tool joints to being less abrasive on the casing, or ‘casing-friendly,’” Mr Juckett said. The company’s TCS hardbanding alloys are designed to ensure joint integrity and crack resistance, as well as casing protection for a wide range of downhole applications. In 1998, Tuboscope launched its TCS 8000 hardbanding alloy, a non-abrasive casing-friendly product that is still used today.

In the Gulf of Mexico, one major operator selected the TCS 8000 line for challenging wells where multiple laterals were being drilled from a single borehole, requiring the pipe to be run in and out of the casing. “Every time the operator drilled a new well, the pipe would come in contact with a certain part of the casing, and the operator wanted that casing protected,” Mr Juckett said.

Tuboscope’s newer TCS Titanium alloy is a more durable hardbanding product that provides casing protection in more challenging well environments. The company also manufactures a TCS Non Mag hardbanding alloy for non-magnetic chrome drill collars used to house steering tools. “The product is designed so as not to interfere with the electronic capabilities of the steering tools,” Mr Juckett explained. Applied as either a stand-alone material or with the addition of tungsten carbides, the Non Mag alloy is highly durable and features welding characteristics that eliminate high heat inputs in the welding process, preventing hot spots, he said.

Using non-hardbanded drill pipe is no longer considered a good way to operate in today’s complex wells, asserted Jason Arnoldy, director of Arnco Technology, a manufacturer of hardbanding products. “Depending on the friction factor associated with the type of hardbanding used, it also can reduce torque and drag significantly, resulting in greater operational efficiencies such as lowered fuel costs from reduced rotating and sliding friction produced by the drill string.

The TCS Titanium hardbanding has unlimited field reapplication capabilities without removing existing hardbanding. Hardbanding is reapplied as needed, pending evaluation. NOV has 80 mobile hardband units that service all major E&P basins worldwide.

“When we think about hardbanding and the direction it’s going, we want to provide products  that are easily understood by the end user and address a range of needs for both the well operator and the drill pipe owner,” Mr Arnoldy said. “These days, the drill pipe owner wants a product that is low-cost and easy for an applicator to apply and re-apply. The key is providing non-cracking products that perform consistently and well in the field, and when they do wear down and go in for service, an additional layer of the same material can be applied problem-free and without having to remove or repair what was previously there.”

Arnco has developed the next generation of its legacy 100XT and 300XT hardbanding products for advanced casing and drill pipe protection. The 150XT was designed to increase wear resistance of the 100XT while maintaining its superior casing friendliness, while the 350XT provides ultra-high wear resistance, like 300XT, but with a non-cracking deposit, making it much more compatible upon re-application on top of itself and other products.

Arnco also is investing toward qualifying its next-generation products for extreme environments, such as sour service and HPHT wells. The 150XT and 350XT have been successfully tested as H₂S-resistant, and additional testing is under way to evaluate the effects of extraordinary temperatures downhole on the microstructure of the hardbanding alloy.

Arnco Technology’s NonMagXT is applied to non-magnetic drill collars that utilize specialized directional equipment to measure various parameters while drilling.

In response to the significant increase in use of non-magnetic drill collars with specialized directional equipment to measure various parameters while drilling, Arnco has developed NonMagXT hardbanding. “The tools required to house this specialized equipment are very expensive and must be non-magnetic to avoid interference with data transmission” Mr Arnoldy said.

The non-magnetic hardbanding, recently commercialized, was designed in partnership with a materials science firm that uses advanced computational modeling to develop advanced alloy systems for rapid testing and proof-of-concept evaluation. “In this case, through rapid sequencing and trial testing, the model ultimately produced an advanced non-magnetic (below a relative

permeability reading of 1.01 per API Specification 7), iron-based hardbanding with very high hardness. Nickel-based non-magnetic hardbanding is difficult to apply and expensive due to the cost of raw materials required to produce it.”

Duraband NC hardband is crack-free and casing-friendly. It is also 100% rebuildable and can easily be applied over most other hardbanding products.

Eliminating spalling 

Hardbanding Solutions by Postle Industries, entered the hardbanding business in 2003 with a hard, non-cracking product called Tuffband NC that prevents spalling, a process that occurs when chunks of hardbanding come off as a result of water, liquid or mud seeping into stress cracks, as well as multiple re-applications.

The company has since developed Duraband NC, which field testing shows can outperform Tuffband 4 to 1. Both products are crack-free, casing-friendly and 100% re-buildable, meaning new hardbanding can be applied over existing layers. They also are suited for H₂S environments, where severe conditions can corrode and severely damage pipe. Ultraband NM, designed for non-magnetic applications when electronic tools are used in the pipe, was introduced in November.

“The trend toward cased holes several years ago sparked the evolution of casing-friendly hardbanding,” said Steve Stefanic, marketing manager, hardbanding, for the company. “For straight open holes, we typically used a steel wire with tungsten carbide, which provides excellent wearability but is extremely aggressive and potentially cuts holes in the casing, leading to increased costs and environmental issues. We needed a solution that wouldn’t damage the casing.”

Duraband has been used in reservoirs worldwide, including Argentina, where it was applied to pipe that drilled more than 350,000 ft, Mr Stefanic said. The crack-free Duraband has been particularly effective in eliminating spalling, which makes reapplication of hardbanding problematic. “Removal of spalling is dirty, costly and time-consuming,” he noted. “After the hardbanding is removed, the hardbanding area needs to be built back up with a mild steel product, then machined down before the new layer of hardbanding can be reapplied, a process that can drive up the total cost by as much as 400%.”

Hardbanding is applied to drill pipe at a thickness between ^3/32 in. and ^1/8-in. Band life varies, depending on hole depth and strata. “In North Dakota, which is characterized by very hard rock, a tool joint with hardbanding might last for one hole,” he explained. “Actual wear conditions in horizontal wells in North Dakota confirmed that tool joint life can be increased more than 500% with just one Duraband hardbanding application over un-banded tool joints.”

Crates of Arnco Technology’s 100XT hardbanding product are prepared for shipment. A new-generation version of the hardband has been developed with increased wear resistance.

If casing wear is not a concern, tungsten carbide can be added to either Duraband or Tuffband. “A recent test in Canada showed that if tungsten carbide pellets are added to Duraband instead of mild steel welding wire, the wear resistance can improve by nearly 500%, drilling 200,000 ft instead of 40,000 ft before replication is necessary,” Mr Stefanic added.

The company has established technical centers in eight locations globally to certify applicators and provide customer support. In 2012, the company introduced a program to identify the experience levels of its applicators, following guidelines that have been developed for pipe inspectors.

The company’s new field training program has been effective in emerging markets where hardbanding is being introduced to support new and under-served drilling markets. “There is a lot of education involved in helping people understand that they can’t put the same drill pipe used in straight holes into deviated holes,” Mr Stefanic said.

Petroserv’s Victoria semisubmersible is working in the Roncador field in Brazil’s Campos Basin drilling development wells under a seven-year contract with Petrobras. The rig can operate in up to 3,000 meters of water.

Brazil remains forerunner in diverse continent of expanding E&P

By Katherine Scott, associate editor

Picture Latin America as a quilt. In unison, the pieces come together to form a vibrant and vast region, but separately, every patch tells a story all its own. “Each country has different needs and challenges regarding both offshore and onshore. It’s not a one size fits all,” said João Geraldo Ferreira, president and CEO of GE Oil & Gas in Latin America. Addressing these individual markets and their own specific needs, from technology to regulations to local content, requires understanding and commitment.

But in a region that has it all – shallow water, onshore, deepwater, ultra-deepwater, heavy oil, conventional and shale gas, and pre-salt plays – it’s still Brazil that’s leading the way in the Latin American energy sector. “Over 90% of what we’re talking about in offshore Latin America is Brazil. And in some respects, in some market focus areas, Brazil drives the global trend,” said Leslie Cook, senior research consultant for Quest Offshore Resources, a market intelligence provider.

Since pre-salt was discovered offshore Brazil in 2005, it has been impossible to mention the country’s E&P landscape without talking about Petrobras. The region’s largest operator in offshore operations in terms of both production and rig count, the company still has a strong hold in Brazil. However, an upcoming licensing round and a general feeling that no single company can cover the country’s offshore resources alone means that IOCs may soon see more opportunities to take part in Brazil’s pre-salt bonanza.

“We can see a good potential market in Brazil, especially in deep and ultra-deepwater,” said Dimas Calani, director of Petroserv SA, a Brazilian drilling contractor. The company has three dynamically positioned drilling rigs operating in the country; one is a fourth-generation semisubmersible, the Louisiana, and two are sixth-generation ultra-deepwater newbuilds, the Carolina drillship and the Victoria semisubmersible. All are operating for Petrobras under contracts running from five to 10 years, with an average dayrate of $440,000.

However, growth is not limited to Brazil. Across Latin America, frontier basins are emerging, with The Falklands, French Guiana, Guiana, Suriname and Nicaragua beginning or expanding initial operations even as more mature areas such as Mexico, Ecuador, Argentina and Colombia push forward. As a result, dayrates have been able to remain strong due to both local and worldwide increases in activity, Michael Acuff, senior vice president of contracts and marketing for Diamond Offshore, said. The company has 12 rigs – 11 semis and one drillship – operating in Brazil. “We really see Latin America as one big opportunity,” he said.

GE Oil & Gas’ facility in Macaé, Brazil, specializes in drilling and subsea services. In the past 30 years, the company has produced and installed more than 180 subsea Christmas trees offshore Brazil.

New Reservoir, New Technology

According to a Petrobras fact sheet, Brazil’s pre-salt is located up to 300 km offshore in water depths that can exceed 2,000 meters with total depth ranging from 5,000 to 7,000 meters. Particularly for Brazil and pre-salt, there’s also belief in the industry that the geology in Latin American countries mirrors that of West Africa. “With the discoveries in West African countries, industry believes Brazil is analogous to Angola. Then, as you go north in Africa, you compare the countries that meet up on the opposite side,” Mr Acuff said. “This has led to exploration programs that are testing the geology to see if it is in fact correlated to West Africa.”

Certainly, the pre-salt wells in Brazil present evident challenges to drilling and because most of the pre-salt wells must go through thick layers of salt and require better technology capability. For GE Oil & Gas, which in the last 30 years has produced and installed more than 1,200 wellhead systems and 180 subsea Christmas trees in Brazil, developing technologies optimized for pre-salt developments continues to be upfront and center, Mr Ferreira said. The company made a $32 million upgrade in 2012 to its Macaé facility, adding a service unit for drilling and subsea production equipment. It is also slated to open a $170 million global research center in Rio de Janeiro Brazil in 2014, with a portion that will be dedicated to oil and gas operations. The center’s research and development resources will also support growth in renewable energy, mining, rail and aviation industries with labs, offices and training.

“Technology is being developed as we speak,” he told Drilling Contractor during the GE Annual Meeting in Florence, Italy, in late January. That technology could be in seismic imaging, MPD or all of the above, because every “single day is a sort of a discovery,” he said, emphasizing that pre-salt discoveries are still comparatively new. “We’ve had technology sessions with Petrobras, where both teams sit down and discuss the technology bottlenecks that have to be addressed, so it’s not what we have today but what has to be invented,” Mr Ferreira said.

More partnerships between Petrobras and IOCs also will foster additional investment and technologies, said Alvaro Teixeira, recently retired executive secretary of the Brazilian Petroleum, Gas and Biofuels Institute (IBP), a private nonprofit organization founded in 1957 that works to make Brazil competitive and investment-attractive by fostering the development of the Brazilian petroleum industry through technical courses and events. Its 220-strong membership counts among its 56 local and international oil and gas companies, including Petrobras, Repsol, Shell, Exxon, BP, TOTAL and Statoil.

One of IBP’s major recent projects is partnering with OTC to hold the 2013 OTC Brasil conference in October in Rio de Janeiro. “OTC is the top event of offshore in the world because it’s the gathering of all the offshore industry of the world. The participation of this partnership of IBP and OTC could bring all the experiences in the world of offshore in Rio, the capital of deepwater offshore exploration and production,” he said.

“Not only does industry need to invest here, but they can bring technology. No country, no company has the monopoly over technology. It’s not easy to drill these wells,” Mr Teixeira said, noting that more than 30 billion bbls of oil have already been discovered in Brazil’s pre-salt. “It just needs to be developed to be confirmed, but we think we will discover in the next 10 to 20 years, more than 50 billion bbls of oil in the pre-salt.”

Another sign of investment in Brazil is the significant numbers of R&D centers that international service and oil companies, such as Schlumberger, Halliburton, Baker Hughes, BG and others, already have and continue to build around the Federal University of Rio de Janeiro campus. “The biggest R&D centers are in Rio,” Mr Teixeira said. “It’s unique in the world to have all of these research centers, as a cluster, just for addressing the technological challenges for the petroleum industry in pre-salt.”

Local Development with Investment in Shipyards

The Deepsea Guarapari (top) and the Deepsea Siri (bottom) ultra-deepwater drillships are scheduled to be delivered by Estaleiro Jurong Aracruz, a Brazilian shipyard located in the state of Espirito Santo, in September 2016. They will both go on a 15-year contract with Petrobras and are jointly owned by Odfjell Galvão and SETE Brasil.

The current forecast for deepwater exploration in Brazil through 2016 is approximately 500 exploration wells, or a total of 800 including development wells, and an average of 2.5 wells drilled per rig each year, according to a Quest Offshore report. Ms Cook said Brazil has always been known as a large exploration area, reaching levels as high as 70% of total drilling. However, since 2011 exploration has declined to 60% of total drilling. “It’s still good, but there’s definitely been a shift out of exploration in mature basin areas as Petrobras focuses more on pre-salt, which takes more time.” The company also asserts that 2013 will be the first year in which no offshore newbuild rigs are actually moving into Brazil, mostly because the country has undertaken shipyard projects to build rigs locally.

Petrobras also finds itself reevaluating its rig needs. In November 2012, the company canceled the process of contracting five ultra-deepwater drilling rigs, capable of drilling in up to 3,000 meters of water, with Ocean Rig Group. According to a Reuters article, it was because Petrobras needed to drill fewer wells in the Santos Basin than originally expected. Last year, Petrobras’ proven oil and natural gas reserves in Brazil reached 15.729 billion bbls of oil equivalent, and its total oil and natural gas production in Brazil averaged 2.44 million bbls of oil equivalent per day in December 2012.

For local companies that want to bring in investment and technologies and for foreign firms that want to solidify their local base, partnership continues to be an important bridge. Odfjell Galvão is a recent project between Odfjell Drilling and Galvão Group, one of Brazil’s largest construction companies, to become a new Brazilian drilling contractor. Odfjell Galvão now has three ultra-deepwater drillships under construction at the Estaleiro Jurong Aracruz shipyard in Espirito Santo. Upon anticipated delivery in September 2016, they will operate for Petrobras under 15-year contracts. Odfjell Drilling also has another deepwater drillship, the Deepsea Metro II, contracted to Petrobras into 2015.

Bjørnar Iversen, CEO and president of Odfjell Galvão, notes that Brazilians are eager to build up the local shipyard and service industries. “They are now building yards up the coast, which means if we have trouble it’s easier to have it addressed. There’s been a challenge of capacities in Brazil, but they are now developing capacities for the oil and gas industry for the future.”

The Deepsea Metro II ultra-deepwater drillship is shared by Odfjell Offshore and Metro Exploration. The rig is currently operating for Petrobras in Brazil.

Mr Iversen believes that Brazil has huge potential going forward. “Brazil is a continent; it’s not a country. It’s so huge, and they have just started to drill here. It’s the beginning of the drilling era in Brazil. It’s not even the first chapter; it’s the pre-amble,” he said. “There are some huge areas still to be explored, and they have huge potential for the future. That’s why it’s not possible for one company like Petrobras to cover all of this. You have to invite someone else to help and to develop Brazil, and I think that will happen.”

An Eye on Regulations

The continued and large-scale development of pre-salt reserves in ultra-deepwater environments has translated into a new focus on regulations in Brazil. “It’s possible to face pre-salt challenges with a consistent regulatory framework that is capable of absorbing quick changes in technology while challenging the industry to improve operations,” said Raphael Neves Moura, general manager of operational safety and environment for the Brazilian National Agency of Petroleum, Natural Gas and Biofuels (ANP) the country’s federal agency responsible for the regulation of the oil sector.

While not in ultra-deepwater, two incidents offshore Brazil have brought E&P regulations to the forefront. In November 2011 and March 2012, Chevron Brasil Upstream Frade found oil seeping into their offshore operations in the Frade Field, located 370 km off the coast of Rio de Janeiro in the northern Campos Basin. The company has since suspended all exploration and development drilling in the field, with the exception of well abandonment activities.

“Although the investigation of the Frade incident has not indicated a relevant change in the regulations, ANP decided to undertake a careful examination on every single offshore well design to be drilled in Brazil to make sure companies are following the approved procedures and good engineering practices during the well construction phase,” Mr Moura said.

Petroserv’s fourth-generation semisubmersible, the Louisiana, is drilling development wells in Campos Basin’s Roncador field offshore Brazil. The rig has been operating for Petrobras since May 1998, drilling in several fields within the Campos Basin; its current contract lasts until May 2015. The rig can operate in more than 2,000 meters of water.

In general, he believes that the Brazilian approach to safety is based on the performance-based/goal-setting model, with few prescriptive requirements and a non-restrictive approach to technological innovations. This means that the operator is able to select the codes and standards and good engineering practices that will be applied for each project as long as they comply with the general provisions of ANP’s safety regulations, Mr Moura said. Nevertheless, all engineering systems are documented by the operator in the Operational Safety Documentation, subjected to ANP review and approval before offshore drilling commences, he added.

“We believe that a goal-setting approach is more effective on challenging the operator to demonstrate the continuous improvement of its safety management system.”

Optimism in Latest Bidding Round

In May, the Brazilian government will hold an 11th bidding round with almost 300 blocks – 122 onshore and 167 offshore – to be offered, not limited to the pre-salt. This will be Brazil’s first licensing round since 2008. “We’ve been stuck because there has not been a new licensing round for years. It’s been just the existing blocks being explored,” Petroserv’s Mr Calani said. The E&P blocks will be distributed over 11 sedimentary basins, five of them onshore: Barreirinhas, Ceará, Espírito Santo, Foz do Amazonas, Pará-Maranhão, Parnaíba, Pernambuco-Paraíba, Potiguar, Recôncavo, Sergipe-Alagoas and Tucano. Further illustrating the growing interest in Brazil’s onshore resources, Petrobras itself recently approved the creation of the Onshore Natural Gas Program to assess natural gas potential.

This licensing round is expected to open up the market to more foreign investments. “More international players will take a larger role in Brazil, creating an even better market,” Mr Iversen said. “It’s going to be interesting to see how this is being sold for the future because there’s been a scarcity of capital.” The new blocks are currently under environmental analysis, and their inclusion in the 11th bidding round is still subject to approval by the National Energy Policy Council.

Petroserv’s Mr Calani noted that there have been a few independents like OGX that have made vital discoveries in Brazil’s shallow water, but they remain sporadic. “The bulk is still deepwater and is the future for years to come with Petrobras leading the show.”

Even as the Brazilian energy market expands on the strength of pre-salt developments, the rest of Latin America is also nurturing rapid growth, including in Mexico, Ecuador, Argentina, Colombia and several emerging frontier areas like The Falklands, French Guiana, Guiana, Suriname and Nicaragua.

“Latin America is a national oil company-driven market, so we approach the region by political block,” Michael LaMotte, managing director, head of energy, Guggenheim Securities said. “You have the absolute control states like Venezuela and Mexico. Conversely, there are countries like Colombia that are attracting outside capital – even though the conventional resource potential is relatively small. Two of the region’s biggest countries, Argentina and Brazil, have started to migrate more toward control states, which we believe will slow the pace of drilling over the near and intermediate terms.”

Mr LaMotte noted that the rig count in Latin America is expected to average 450 this year, up from the 2012 average of 423. Most markets within the region should move sideways this year, he added, with the exception of Mexico, which alone is expected to account for about half of the region’s growth. “Colombia should be up by more than the region’s average as well; however, it is growing off of a relatively small base. And although the potential of the Vaca Muerta formation in Argentina is truly world class – for both natural gas and liquids – we expect growth in drilling to be fairly anemic this year, as operators continue to learn more about the resource.”

Countering the market growth in frontier areas, however, is the steady activity of the region’s NOCs. “The government controls both the regulatory and environmental agencies, and they dictate the pace of lease sales and partnering,” Mr Acuff explained. In frontier areas, the government regulatory framework is typically not as developed, which can speed up the process. “In several of these countries, there is not a history of oil and gas exploration so they’re interested in bringing in the IOCs to utilize their technology and experience,” he said.

In general, he continued, as more NOCs in Latin America go offshore, they will look for additional experience and expertise from IOCs. “That’s one of the areas that is driving the growth for the IOCs and the growth in Latin America,” Mr Acuff commented, adding that Diamond Offshore is focused on activities in Colombia, Nicaragua, Suriname and Guiana. “We’re hoping they are successful because it could be a very large market if they hit what they are targeting.”

Diamond Offshore’s Ocean Valor semisubmersible has been operating offshore Brazil under a contract with Petrobras since it was delivered from the Jurong shipyard in 2009. The rig can operate in more than 3,000 meters of water and is capable of drilling wells more than 12,000 meters deep.
Image courtesy of Diamond Offshore

A May 2011 report by the US Department of Energy identified Argentina as having the world’s third-largest shale resource base, behind China and the US. However, the drilling and completions model in Argentina is different from that of the US. “For starters, the Vaca Muerta is a stacked reservoir, with plenty of vertical well potential,” Mr LaMotte said. “Although the number of horizontal wells drilled in the country will continue to grow, the number of new rigs needed for the Argentina market is likely to translate into a handful each year for the next few years, as mobility is not yet a premium in the market like it is in the US.

“Compared to the advanced rigs in the US, the rigs in Argentina just don’t move around as much. They are on location a lot longer just because drilling times and completion times tend to be so much longer.”

The productivity of the services industry is another issue in the Vaca Muerta, Mr LaMotte continued. “Currently, frac crews are able to complete about one stage per day, whereas the same crew working in the Eagle Ford, for instance, could probably average about eight stages per day. That has to do with the availability of water, sand and proppant, rail and truck infrastructure, etc.”

Besides productivity challenges, another matter in Argentina is concentrated lease ownership, meaning millions of acres are often being leased by only a few operators. “In the US, one of the reasons why we saw activity take off so quickly is that you can put 100 operators and 30 contractors into a well-defined region, and let them figure the play out through trial and error. Because all of the companies learn from each other, the cost of any one company’s experimentation is relatively low, and the learning curve of the entire basin improves quickly,” Mr LaMotte said. “In a basin like the Vaca Muerta, a single operator isn’t going to blitz a million acres at the same time – they don’t have the human resource to address it – and from a returns standpoint, it risks too much capital. Consequently, the pace of activity will naturally be a lot slower.”

For conventional resources, one setback was the recent dispute between the Argentinian government and Repsol. In April 2012, Argentina’s president Cristina Fernández de Kirchner announced that the country would take back majority control of YPF, which was 57% owned by Repsol at the time. “The government of Argentina wanted to see the cash being generated by YPF reinvested in Argentina,” Mr LaMotte said. “Since the takeover of YPF, the company has stepped up investment locally, and we see ventures with large IOCs as incrementally positive over the long term.”

In a report by Quest Offshore Resources, exploration well demand in South America is exponentially higher than development well demand. For both types of wells, demand is expected to increase at least until 2016, with total well numbers reaching over 800 between 2013 and 2016.
Source: Quest Deepwater Drilling Analysis – January 2013

Last year, Ecuador’s economy was the second fastest-growing economy in Latin America, Fernando Navia, a trade commissioner for Ecuador, said at a licensing round road show in Houston on 4 February touting his country’s petroleum exploration opportunities. To encourage energy industry investments, Ecuador has been marketing its southeastern bidding round, where 13 oil blocks are up for licensing. Contracts are expected to be signed in Q3 this year.

“This is a very big day and a new era for Ecuadorean oil as a key driver of the national sustainable development,” Mr Navia said. The income generated by oil is distributed mainly to socio-economic investments, such as education, healthcare, social protection and infrastructure.

The Ecuadorean government also continues to work with local communities to ensure expectations are met as far as environment and safety. “Our reality in Ecuador is that communities and indigenous nationalities are supporting this bidding process. In these signed agreements, each community leader is agreeing with the government for $3.4 million of profits from these blocks to go toward programs for social development,” Andres Donoso Fabara, undersecretary for land management contracts allocated and hydrocarbon for Hydrocarbons Secretariat of Ecuador (SHE), said.

Until results are in from the 2013 bidding round, it’s believed that the country has the infrastructure and the capital but is limited by its resource potential. “They’re doing what they can with what they have,” Mr LaMotte said. “Growth is going to be modest as a result of the change from a production sharing system to a services agreement system, but it should continue to come from the reworking of old fields, where the priority is to grow production by raising recovery factors.”

According to a report by Quest Offshore Resources, in 2012 South America contracted 83 rigs but needed only 72. However, it is expected that by 2016, 92 rigs will be contracted when the region will need 96 rigs. It also forecasted that well demand will increase every year.
Source: Quest Deepwater Drilling Analysis – January 2013

Sharing the deepwaters of the Gulf of Mexico with the US, Mexico continues its step-out into deepwater, although the country’s political framework and processes still pose challenges. “Mexico is just PEMEX because of the way the laws are set up, so it’s a one-operator job,” Quest Offshore’s Ms Cook said. “They’ve brought in four rigs over the last two years that are brand-new ultra-deepwater rigs with average dayrates of half a million a day, and they have five rigs under contract now. Three have been working, one is getting ready to start, and all are drilling in ultra-deep.”

There have been only approximately seven deepwater discoveries over the past three years, with an average of one to 1.5 wells drilled per year, she continued. “PEMEX doesn’t have a lot of experience in deepwater, and they don’t have a lot of help. They’re doing it a lot themselves, and until the laws change, we see that to be very slow, but it looks like there could be something good there.”

With Mexico’s presidential election in July 2012, a lot of hope has been pinned on the campaign platforms of the country’s new leader, Enrique Peña Nieto, as well as many members of the Mexican Congress, that energy reform will take place in the next couple of years, Mr Acuff said. Diamond Offshore currently has five jackups operating for PEMEX and continues to look for new opportunities to add rigs to the Mexican market, particularly as PEMEX continues to step out into deeper waters. In April 2011, the NOC signed a five-year, $850 million contract for Seadrill’s West Pegasus ultra-deepwater semisubmersible, which would go on to drill the Supremus-1 discovery well in October 2012 while drilling with the rig.

“PEMEX in deepwater could be a big story,” Mr Acuff continued. “They’re continuously looking to add floating drilling rigs, so we’re excited about the area and hope they have success there to spur additional growth in Mexico.”

NOV’s Ideal Prime rig, which will officially launch in Q2 2013, features optional dynamic fuel-blending technology. A control system dictates how much power is needed for the engine during a given time throughout the operation, leading to reduced emissions and better performance.

Industry building environmental stewardship into rigs, technologies, operations, enhancing emergency preparedness and public outreach

By Joanne Liou, associate editor

Like the path that has been taken to achieve safer operations, industry has come a long way in improving its environmental performance, taking incremental steps that are adding up to significant change. “In the last 20 years or so, we have done a tremendous job in creating safe operations, and most well-managed companies have satisfactory safety performance,” Michael Ellekjaer, head of corporate social responsibility at Maersk Drilling, told Drilling Contractor. “However, I think we, as an industry, have to give the same attention to the environment, i.e., spills and waste management. I see the industry moving more and more in this direction, and it is the right direction.”

As operations have increased in complexity and our reach expands further into sensitive environments, the need to balance between global energy security and environmental stewardship is becoming more pronounced. “What happened slowly with safety was the costs were internalized. If someone was injured, the company was aware of the associated costs in healthcare and downtime,” Natalie Wagner, cross-divisional environmental solutions at National Oilwell Varco (NOV), said. “That’s not necessarily part of the environment side, yet. People have been having difficulty getting their license to drill for permitting purposes, and once the costs are appropriately connected to the environmental impact, I think we will see more importance put on the environmental side of HSE.”

Industry maintains a record of continuous improvement, as seen in technology, safety and increasingly in the environment, David McBride, director – environment, health and safety, Anadarko Petroleum, said.

“Early engagement and transparency are keys to success in the new oil and gas world,” he said. Notable progress has been made on the environmental front, with a shift that’s just starting toward natural gas engines, the development of documentation to measure improvements in emissions and spill prevention, and emergency preparedness.

The evolution of the industry’s safety culture, which includes everything from enhanced and well-documented training to technology advances that remove workers from high-risk areas, is emblematic of the approach that the industry is also taking with the environment.

All Maersk Drilling rigs, including the MAERSK INSPIRER, have a waste management system. ISO14001 maps out a framework for setting up an environmental management system to reduce waste management costs, lower energy and materials consumption, and cut distribution costs.

“We must manage and control our impacts as much as practically possible,” Mr Ellekjaer said. “We work hard to ensure that constant care is embedded in our organization … to include environmental perspective in our decision making and risk management.”

Technology and safety by design plays a significant role in improving safety performance, and the same approach is helping industry to enhance environmental performance as well. Industry is finding practical solutions that utilize available resources with lower costs and lower emissions.

On its land rigs, NOV is incorporating drilling packages with natural gas engines or dynamic blending systems. The Ideal Prime rig, which will officially launch in Q2 2013, features an optional dynamic gas blending (DGB) system from Caterpillar Oil and Gas. The DGB technology automatically adjusts to changes in incoming fuel quality and pressure allowing engines to run on a wide variety of fuels, from associated gas to vaporized LNG without sacrificing performance integrity, Ms Wagner said. “It could be idling; it could be full throttle. It could be 30% diesel and up to 70% natural gas. The goal would be to have better emissions and performance.”

The engine of Nabors’ new PACE-X rig is designed to operate with up to 70% natural gas, reducing diesel use and therefore the number of diesel truckloads driving to location. Four of the rigs have been deployed to the Haynesville; 20 more are planned to be delivered this year.

Also featuring a dual-fuel system, Nabors’ new PACE-X rig is designed to operate with up to 70% natural gas. For each well, an average of 25% of the diesel required can be substituted with natural gas. “The engine’s natural gas usage is based on the power demand of the rig. The engine will automatically adjust the control valve that supplies natural gas to engine,” Todd Fox, vice president – engineering & technical services at Nabors, said. “If the engine needs to respond more quickly to rig power demand, it will curtail the natural gas and switch over to diesel. Dual-fuel systems provide an excellent alternative to 100% natural gas engines that must be larger due to the drop in horsepower experienced when operating on 100% natural gas.”

In addition to fuel savings, reducing diesel use translates to fewer diesel truckloads driving to location, Mr Fox said. Further, emissions are reduced with a catalytic converter that is placed on the exhaust, before the muffler. Nabors is deploying four PACE-X rigs in the Haynesville play and is ramping up to deliver more than 20 PACE-X rigs this year to reach the major plays in the US.

The Environmentally Friendly Drilling Systems Program (EFD) acknowledges the benefits of natural gas-powered engines – lower costs and lower emissions, but the group also sees an opportunity to capitalize on that benefit by quantifying it. Funded by industry, government and environmental organizations, Texas A&M University and the Houston Advanced Research Center (HARC) founded the EFD program in 2005 to provide unbiased science to identify and develop solutions to address issues associated with oil and gas development.

One of EFD’s core areas is to determine the drilling footprint from site to emissions. “Several of our sponsors have a mission to convert their rigs to natural gas, and we’re working directly with them and companies that provide those services, not only to make sure it gets out into the field a little faster, but also to document the benefits,” Thomas E. Williams, senior adviser of EFD, said. “We’ll provide that data back to our sponsors and then share it with the media and hopefully encourage what needs to be done.”

Dual-fuel fracturing operation proves LNG feasibility in high-hp applications

An LNG truck arrives at the site of an Apache hydraulic fracturing spread in Oklahoma’s Granite Wash play. Linde North America delivered and provided onsite storage and vaporization of the LNG that replaced 60% of diesel consumed in the 12-pump, 24,000-hp fleet.

By Katie Mazerov, contributing editor

In an Apache Corp hydraulic fracturing operation fueled by a combination of liquefied natural gas (LNG) and diesel in Oklahoma’s Granite Wash play, 60% of the diesel was replaced in the entire 12-pump, 24,000-hp fleet. The operation was engineered by Linde North America, which provided the LNG, its onsite storage and vaporization, and technical support.  Since the Apache operation, Linde has also been selected to supply LNG and related equipment and services for CONSOL Energy in the Marcellus and Utica basins, said Earl Lawson, head of Energy Solutions for Linde.

“The Granite Wash project proves the feasibility, safety, effectiveness, efficiency and logistical benefits of using economical, clean-burning LNG in the high-horsepower applications required for large-scale hydraulic fracturing operations,” Mr Lawson said. “The dual-fuel operation was essentially an evolution. We started by using LNG in a couple of engines and expanded to convert the full frac spread of 12 engines that were outfitted with conversion kits that allowed them to run on both fuels.”

As the amount of gas fed to the frac fleet and number of dual-fueled engines increased, the gas supply system and conversion kits were tested to determine how the engines performed and how much diesel could be displaced, he explained. Halliburton provided the manifold that connected the gas supply to the engines and worked with Linde engineers to properly integrate the pressure, flow and safety aspects of the operation.

Environmental, economic benefits

“Use of LNG in hydraulic fracturing operations has huge environmental benefits and provides significant economic advantages,” Mr Lawson noted. “LNG is a high-density fuel; six times as much can be stored onboard in a liquid form than in a gaseous, compressed form. In high-hp applications, where a lot of fuel is being consumed in a short period of time, the ability to economically transport the LNG, bring it onsite as a high-quality gas and store it safely is very cost-effective.”

Under the new contract with CONSOL Energy, Linde initially will supply LNG to power drilling rigs and will eventually provide fuel for hydraulic fracturing, mining and marine operations. The agreement follows a successful trial operation by the two companies using Linde’s LNG solutions to replace some of the diesel fuel used to power the engines that drive the drilling rigs.

“We are starting to see a lot of interest and demand for dual-fuel systems because of environmental concerns,” Mr Lawson said. Going forward, he believes there are no technical limitations to increasing the use of LNG in fracturing operations. “LNG is already being used to fuel the trucks that carry the water, sand and chemicals used at frac sites,” he said. “There is no reason we can’t convert the engines providing the horsepower for the fracturing operations themselves, as long as we have the infrastructure in place to ensure LNG remains a reliable and safe fuel.

“We need to focus on the safety aspect of what we’re doing by putting the right practices, procedures, people and equipment on the ground to ensure LNG can safely deliver the inherent environmental benefits and economic value for the industry,” he added.

A division of The Linde Group, Linde North America also has been supplying CO₂ and nitrogen for the gas completion process for 35 years.

Maersk installed electronic compensators in the main engine rooms of the MAERSK GUARDIAN (pictured) in 2011 and the MÆRSK GIANT in 2012. The compensators reduce diesel consumption and limit the power for the wattles, which improves power quality and enables generators to produce more active power, said Michael Ellekjaer, head of corporate social responsibility at Maersk Drilling.

Based on findings from a 2009 project focused on four main areas: energy efficiency and emissions, discharge, accidental spills and water management, Maersk Drilling has taken steps to save energy and reduce CO₂ emissions on its rigs. “Over the last two years, we have installed electronic compensators in the main engine rooms of our rigs – MAERSK GUARDIAN in 2011 and MÆRSK GIANT in 2012 – to lower diesel consumption,” Mr Ellekjaer explained. “The compensators work by limiting the power needed for the wattles, thereby improving power quality and enabling the generators to produce more active power. An additional benefit of a compensator is that it reduces the harmonics in the electrical system, which also delivers fuel savings and improves the lifetime of electrical components (e.g., florescent light fixtures).”

Although equipment upgrades can provide incremental improvements in environmental performance, Maersk Drilling believes bigger gains can be made in the design of new rigs. “Our drillships will deliver 8.5% minimum reduction of energy, and the XLE jackups deliver 10%,” compared with the average

emission of the 16 rigs in Maersk Drilling’s fleet today, Mr Ellekjaer stated. Additionally, Maersk manages a constant but changing catalogue of projects from harmonic filters to removing leaks on the rigs, which saves energy and reduces NOx emissions. A challenge is identifying a metric to benchmark performance. “Part of the strategy is to ensure we have a full understanding of the energy footprint of our rigs and will use an Energy Efficiency Management Plan to monitor, control and document where we are using our fuel,” he noted.

In 2012, the company’s number of spills increased from 18 in 2011 to 34 in 2012. Despite the overall increase, the volume spilled remained level at 20,000 liters (5,283 gallons). Approximately 44% of spills in 2012 were caused by or related to a failure, burst or rupture of hoses. Maersk Drilling is actively implementing programs on hose management, overboard work and increased focus on maintenance and the relation to spills.

Compared with Maersk Drilling’s current fleet, three XL Enhanced jackups under construction are expected to deliver a 10% reduction in the energy required.

Rating systems

An EFD project, Scorecard, began about four years ago and is based on US Green Building Councils’ LEED program. The Scorecard assesses land-based drilling operations and technologies with respect to air, site, water, waste management, biodiversity and societal issues, from the time a permit is obtained to completion. Led by Dr Richard Haut, senior research scientist at the HARC, service providers such as Halliburton and more than 40 other organizations, including IADC, the Environmental Defense Fund, the Nature Conservancy, operators and regulators, were among participants who helped define specific attributes to assess operational systems applied by drilling contractors and operators. A scorecard created under the project assists operating companies in planning and implementing practices to manage operational risks, while landowners, regulators and the public can use the scorecard to objectively assess the operator’s performance.

“The challenge is in the geographical and geological differences. A process that you do in the Rockies may not be the same thing you do in the wetlands or Appalachia,” Mr Williams said. “This is still a learning process. We’ve defined ecosystems as a way to make adjustments based on the different areas.” Sponsors of the initiative are beta-testing the scorecard on a site-specific basis, and EFD expects to fully launch it later this year.

NOV began an initiative last year to create a report card to rate equipment’s environmental performance. The company has applied it internally to iron roughnecks to improve performance in terms of environmental protection.

Targeting the needs of customers and to help meet regulatory requirements, many of which are constantly changing, NOV began an initiative about a year ago to create a report card focused on environmental performance. Along the same lines of the US Environmental Protection Agency’s ENERGY STAR ratings for energy efficient products and practices, NOV is creating a rating system for drilling equipment. “The ultimate objective is to improve the performance and reduce the impact on the environment for oil and gas wherever you are, specifically for drilling,” Ms Wagner stated.

The NOV reporting initiative is based on existing approaches or established standards, such as ISO. Under a controlled boundary, “we are thinking of the things we can influence versus the things drilling contractors or operators can. We can really only employ things to the manufacturing and operational lives of our equipment. We can’t dictate how they will be used, but we can say what should happen over their lifetime,” she said. NOV has applied the report card internally to iron roughnecks to improve their performance in terms of environmental protection. An issue for offshore equipment is whether they are compatible with environmentally friendly hydraulic fluids, and “that’s something we have to go back to the OEMs for in terms of filters, seals and cylinders to see if they can show it’s compatible,” Ms Wagner noted.

Still in the research and development stage, the report card is on the agenda with the IADC Environmental Subcommittee that is meeting in April. A workgroup will be started to solicit input from IADC. “We’re looking to propose it to other members of the Petroleum Equipment Suppliers Association to see if it would be something that could be applied to industry manufacturers for oilfield equipment across the board.”

Click here to view the embedded video.

Ken Murphy, CEO of Enviro Clean Products & Services, talks about spill prevention, control and countermeasure (SPCC) plans with Drilling Contractor associate editor Joanne Liou at the 2013 IADC HSE & Training Conference last week in Houston. Understanding the federal regulation, which became effective in 1974 but has become a greater concern in recent years, is important in order to implement a practical plan covering the three key areas of prevention, control and countermeasures.

Offshore emergency preparedness

Click here to view the embedded video.

In recent years, industry has significantly expanded its capability to quickly and comprehensively respond to an uncontrolled deepwater well blowout or spill. Groups, such as Wild Well Control, the Subsea Well Response Project, Marine Well Containment Company (MWCC) and Helix Well Containment Group (HWCG), stand ready to respond should an incident occur.

The Q4000 semisubmersible well-servicing vessel is part of the Helix Fast Response System (HFRS), which will be used by the Helix Well Containment Group (HWCG) to respond to any uncontrolled deepwater blowout or spill in the Gulf of Mexico.

A federal government mandate issued after the Macondo incident requires oil and gas companies operating in deepwater, defined as 500 ft or more, to have adequate spill response and well containment resources under contract. MWCC and the HWCG were founded in 2010 to fulfill requirement in the US Gulf of Mexico (GOM). Now, essentially all deepwater operators operating in the GOM are a member of either the MWCC or HWCG; 10 companies belong to MWCC, while HWCG has 24 members. Both groups have solutions to operate in water depths up to 10,000 ft and can handle well pressures up to 15,000 psi.

“We developed our whole system to be able to minimize the effects of a well blowout,” Roger Scheuermann, commercial director at HWCG, explained, “and we feel that we can cap a well for shut-in within six days.” HWCG has two dual-ram capping stacks available – the first is a 13 ^5/8-in., 10,000-psi capping stack located in Ingleside, Texas, and the second is an 18 ¾-in., 15,000-psi unit located in north Houston. “They’re separated because we didn’t want to put both of them in a hurricane area,” he noted. Once called out, the capping stack would be tested and loaded onto a boat within 24 hrs to 36 hrs and deployed to the well location.

The 13 ^5/8-in. capping stack is part of the Helix Fast Response System (HFRS), which is owned and operated by Helix Energy Solutions Group and utilized by HWCG. The HFRS also includes the Q4000 semisubmersible well-servicing vessel and the Helix Producer 1 (HP1) floating production unit (FPU), which were part of the response solution in the Macondo incident. The vessels, which are required to stay in the GOM in case of an emergency, are operated daily to ensure immediate mechanical readiness. The 13 ^5/8-in. capping stack and HWCG’s response processes will be deployed in the first half of 2013 in an exercise overseen by the Bureau of Safety and Environmental Enforcement (BSEE).

HWCG’s 13 5/8-in., 10,000-psi capping stack will be deployed later this year in an exercise overseen by the US Bureau of Safety and Environmental Enforcement.

HWCG has developed a well containment plan addressing three scenarios: 1) a rig that sinks and goes off to the side of the well, 2) a rig that sinks and falls directly on the well, or 3) a well blowout that occurs while the rig is still attached to the well. “Our initial process will require site assessment with remote-operated vehicles, so we know whether we have access to the well,” Mr Scheuermann explained. “If we don’t have vertical access, we’ll have to call out debris removal equipment so we can latch the capping stack on top of the BOP or the wellhead.”

If it is not possible to shut in a well due to pressure integrity, which may cause casing to burst or broaching around the well, the system would follow a flow and capture strategy. “We would have to run an intervention riser system and initially take flow back to the Q4000. From there, we would offload to our HP1 FPU, process the oil and gas and then discharge oil to a storage vessel,” he said. The system has the capacity to handle 55,000 bbls of oil/day and 95 million cu ft of gas/day. HWCG is working on an expanded system that will be capable of handling 75,000 bbls of oil/day.

Under HWCG’s response system, dedicated equipment is required to work only in the GOM and be available in case of an emergency. The primary equipment – the Q4000, HP1 and HFRS – is maintained daily in the GOM, and crews are trained and ready to respond to an emergency. “HWCG’s member companies have received approval for over 50 drilling permits, and HWCG has participated in more than 50 drills with our members,” Mr Scheuermann noted.

The Helix Producer 1 floating production unit is part of the HFRS and was part of the response solution in the Macondo incident.

All 24 members of the HWCG have signed a mutual aid agreement, which allows each company to share equipment, resources and personnel in an emergency situation. “In our database, we have over 250 people we can reach out to with a single notification,” he said. “While an overall response, including surface spill removal would require substantially more people, during HWCG drills, on average, we receive over 100 responses of members able to respond to the well containment event.” The communication system sends notifications to office phones, cell phones, emails and by text message. People have the opportunity to respond whether they are available, which allows the source control team to set up day shifts, night shifts and long-term transition teams.

HWCG also has established a Deepwater Intervention Technical Committee (DITC) made up of members of the consortium, which includes technical experts who meet once a month to discuss engineering challenges and to develop solutions. The group is looking to expand the response system to ensure that adequate equipment, processes and procedures are in place. Ongoing studies also are being considered with effects of HPHT on specific pieces of equipment.

During the exercise, the MWCC capping stack was lowered approximately 6,900 ft below the water’s surface, where it landed and latched onto the simulated wellhead. Pressure testing confirmed the capping stack’s ability to control a well.

In summer 2012, at the request of the US Department of the Interior and BSEE, MWCC mobilized its containment system, including the deployment of its 15,000-psi, single-ram capping stack, which stands roughly 30 ft tall, 14 ft wide and weighs about 100 tons, and provides a dual barrier for containment – a BOP ram and a containment cap. The capping stack was lowered approximately 6,900 ft into the GOM and latched to a simulated wellhead, where all necessary functions and pressure testing were completed, and equipment performed as expected, Marty Massey, chief executive officer of MWCC, told Drilling Contractor. After the demonstration, MWCC hosted information sessions with its member companies to educate and share key learnings and to open a dialogue about how procedures could be enhanced.

The MWCC system has the capacity to contain 60,000

During a deployment exercise in summer 2012, MWCC mobilized its capping stack to a simulated well at Walker Ridge 536 in the US Gulf of Mexico.

bbls of oil/day and 120 million cu ft of gas/day. Much of the system is housed at ASCO on the Houston ship channel. Other components are stored at vendor facilities in Fourchon, La., and Houston. MWCC is currently working on an expanded containment system with the capacity to contain up to 100,000 bbls of liquid/day, as well as handle up to 200 million standard cu ft of gas/day. Members have committed more than $1 billion to build the expanded containment system, which will be available later this year, Mr Massey stated.

MWCC is currently accepting a 10,000-psi capping stack from the contractor and completing final function testing for regulators. The capping stack will be used in tension leg platform and spar applications with tighter well spacing, which will bring MWCC’s capping stack count to two.

Recognizing industry’s relationship with and impact on the environment is cultivating a cultural shift as well as leading to more actions being taken, not only internally within the industry but externally in the public’s eye. Through public outreach and coalitions, such as the Marcellus Shale Coalition (MSC), industry is actively engaging communities and promoting its operational transparency with fact-based communication. “That’s what differentiates us from those on the other side of the issue, who resort to fear rather than facts,” Steve Forde, vice president of policy and communications for the MSC, noted. The MSC, founded in 2008, comprises more than 300 member companies operating in the Marcellus and Utica Shale plays.

The coalition has published recommended practices (RPs) specific to the region, ranging from site planning, development and restoration to water pipelines. “You’re only as strong as your weakest link when you’re an organization as large as ours,” Mr Forde said. “We want to make sure all those links are strong, and by raising the bar in the way these RPs do, we’re certain that we’re staying ahead of regulations that we’ll be responsible for complying with.” The coalition has several sister organizations across the US, such as the Ohio Oil and Gas Association, the Pennsylvania Independent Oil and Gas Association, and the West Virginia Oil and Natural Gas Association.

A Range Resources rig operates in the Marcellus Shale. The company was instrumental in forming the Marcellus Shale Coalition, which actively engages communities and promotes operational transparency.

To ensure that wide-ranging perspectives are included, environmental and conservancy groups have participated in the development of the MSC’s RPs. For example, for site development and restoration, the American Chestnut Foundation, which supports the heritage of the chestnut tree common to parts of Pennsylvania, worked with the coalition to reintroduce the species to areas where development occurred, Mr Forde explained. “We can restore these development locations as closely to the way they originally looked before.”

The coalition realizes that its message is only as effective as the number of people it reaches. In 2012, the group launched the LearnAboutShale.org project to provide information to the public in the greater Philadelphia area, where there is not any active drilling. “However, there is a huge population base, a number of influential policymakers, and it was very clear our industry needed to do a better job of communications to that particular part of Pennsylvania,” Mr Forde said. “The more that we can show Pennsylvania that their land and our land are safe, their water and our water is safe, and we’re residents of this community as well, the more confidence we’ll continue to see.”

The website is just one example of how industry continues to respond to the public’s need  for more transparency, and the coalition recognizes legitimate questions exist across a variety of different stakeholders. “The best way to relate to the largest amount of people is to be straight with them. We give them the facts to describe the process, which has been perfected in the last decades, in hydraulic fracturing – exactly what takes place and what steps are in place to protect ground water. We’re responsible for participating in an honest conversation with them.”

In the Marcellus, Anadarko Petroleum’s Appalachian Basin management team partnered with the Northcentral Pennsylvania Conservancy to conduct a stream bank restoration project, which began in 2010 near the company’s natural gas operations. Recognizing the potential and the importance of protecting the area’s other natural resources, Anadarko is working with the Pennsylvania Fish and Boat Commission and community volunteers to restore the environment.

Company initiatives

Although industry often solves problems on its own, Mr McBride of Anadarko urged that companies also should not overlook the opportunity to engage the public when an issue arises. “When dealing with community impacts, community engagement is a key aspect for people to feel included. Their voices are heard, and you’re listening to them. You understand what their concerns are,” he explained. “You’re going to solve that problem with them instead of for them.” In the US, Anadarko operates in shale and resource plays in the Rocky Mountains region, the Southern Region and the Appalachian Basin. The company also operates in deepwater GOM and has production in Alaska, Algeria and Ghana.

There is a strong focus in this industry on safety first, Mr McBride said, and the importance of environmental protection is also essential in addressing concerns from the public and regulatory communities. The chemicals used in fracturing fluids have been a recent public concern, and operators, such as Anadarko, have worked to improve the transparency of such operations by disclosing those fluid ingredients on the national hydraulic fracturing chemical registry, FracFocus.org. Launched in April 2011, the site has approximately 350 reporting companies that have registered more than 37,000 hydraulically fractured well sites, along with the chemicals used in their fracturing.

In retrospect, looking at where the debate was headed a few years ago on frac disclosures versus what the industry has proactively put in place and where it is headed today, it is an illustration of the effectiveness of communication on a local level, Mr McBride said. “Industry has been very successful at meeting the expectations of many citizens and stakeholders. We’re seeing more localized attention to FracFocus and to frac disclosures, but we’re not seeing massive federal efforts to try to regulate frac fluid disclosures,” he noted. The collaborative effort between industry and local communities exemplifies how states are best equipped to deal with oil and natural gas issues on behalf of their communities.

Internally, companies have implemented programs integrated within safety initiatives to enhance employees’ environmental awareness and responsibility. Anadarko’s LiveSafe program, launched in 2009, addresses cultural alignment among employees, including drilling contractors on location. New-hires and contractors complete training as they come to work for Anadarko. “It addresses the man or woman in the mirror to make sure when he or she shows up for work, it’s eyes on task – understanding their role, responsibilities, stop work authority and not being afraid to use it,” Mr McBride explained. “It’s understanding the mechanical integrity of equipment operations, which can be an environmental component and ensures our ability to operate responsibly.”

At Maersk Drilling, environmental issues are systematically integrated into its operational processes and are reiterated in safety procedures, i.e., job safety analysis, report cards and toolbox talk. Environment awareness is also monitored through the company’s annual employee engagement survey. “We ask two questions about 1) if your manager encourages you to
consider environmental aspects in your work, and 2) if the company is making genuine efforts to protect the environment,” Mr Ellekjaer stated. Based on feedback, senior management must work on improvements if targets, in which 80% is favorable, are not met.

Left: The Environmentally Friendly Drilling Systems Program (EFD) developed a virtual rig website to understand how technologies can reduce the impact of drilling operations on the environment.

In simple terms, industry’s mantra can be put as, “do my job, be safe and don’t hurt the environment,” Mr Williams of the EFD said. “They figured the safety part out – training and extremely good documentation. There’s still an evolution on how we consider environmental performance and how we document those things. Everybody has the same goal; there’s just a lack of the same types of tools to get there that we have in safety.” The common challenge is gaining leadership support, defining practical goals and how to account for them. “The environmental culture is just like safety culture; it starts at the top. If the CEO and the board of directors are totally committed, that company will develop that environmental culture of safety,” Mr Williams added. “The only way you can really judge it is by documenting.”

Companies, such as Maersk Drilling and NOV, have recently begun to publish sustainability reports, and more companies are starting to follow suit. Sustainability reports address environmental, social and energy performance and typically provide qualitative and quantitative metrics to detail progress made and opportunities for improvement. “It’s all about developing that culture. That momentum, the leaders of the world who really understand the value of getting out beyond our walls of the oil and gas industry are still needed,” Mr Williams stated.

 

During a deployment exercise in summer 2012, MWCC mobilized its capping stack to a simulated well at Walker Ridge 536 in the US Gulf of Mexico.

Work in progress

As industry continues to operate under the public’s critical eye, advances in rig technology and lessons learned in emergency preparedness and community involvement is setting a foundation for a prosperous future. “Part of the operating philosophy applies overseas as well,” Mr McBride noted. “(Anadarko) has a very easy way of applying those lessons as we see the potential growth of shale development internationally. We are engaging early and often to explain how we do our business.”

Everyone has a role to play until there is zero impact from drilling and resources are developed without a measurable impact or change in the surrounding environment, Ms Wagner of NOV said. “I say we have come quite a ways. I don’t think we are there, yet. I’m not sure we know how to say when we’ll get there. We have a long future in front of us, and we’re making improvements.”

“Transparency and honest fact-based communication is really the best way to inspire confidence with the public, regulators, legislators and a variety of stakeholders,” Mr Forde said. “It’s human nature to be skeptical on the outset of any issue that is relatively new to the community. The greatest testament to our commitment has been safe development of a resource over time.”

2013 Drilling Conference chairman Øystein Arvid Håland will kick off the conference at an opening session on 5 March in Amsterdam.

The 2013 SPE/IADC Drilling Conference and Exhibition, 5-7 March in Amsterdam, will provide leading industry thinkers the opportunity to meet, discuss, evaluate and share ideas to advance worldwide drilling and completion operations.

Topics at the conference will include tubulars, well technology and field development, management and systems, and more. The program includes more than 100 papers, 37 e-Posters and a plenary session. A luncheon will be held on 6 March providing young professionals the chance to discuss industry and career topics with experienced professionals in a relaxed setting.

In the opening session on 5 March, welcome remarks will be provided by the 2013 Drilling Conference chairman, Øystein Arvid Håland, head of drilling & well for Statoil and a senior representative from SPE, as well as 2013 IADC chairman David W. Williams,chairman, president and chief executive officer of Noble Corp. The SPE Drilling Engineering Award also will be presented.

On 6 March, Ole Slorer, managing director of global oilfield services for Morgan Stanley Research will moderate the plenary session, “Delivering Wells in a Critical World,” that explores how the drilling industry is affected by and how it should respond to increased demands and growing expectations from its stakeholders.

In light of these expectations and increased public awareness about the impact of energy exploitation and use, how should our industry develop and evolve?

Get up-to-date information on the 2013 IADC/SPE Drilling Conference and Exhibition.

Image courtesy of Ensco

By Linda Hsieh, managing editor

For all the big iron the drilling industry has spent billions of dollars building that can lift millions of pounds and drill miles beneath the earth’s surface, for all the highly sophisticated downhole technologies that can match anything in the aerospace or nuclear industries, much of our efforts are now circling back around human factors: training, competency, organizational culture.

Much of it is interrelated, and it still all goes back to safety. “The highest priority continues to be safety of personnel performing drilling operations,” said Thomas Burke, Rowan Companies chief operating officer and 2013 vice president of IADC’s offshore division.

Industry is also recognizing higher stakes in the public arena, particularly in the development of shale oil and gas. Talisman Energy senior VP of global drilling and completions Kevin Lacy points out that such unprecedented proximity to the general population is calling for unprecedented levels of transparency in our operations as well. “Any mistake can be multiplied in the public arena to taint the reputation of the entire industry,” he noted.

Offshore and on land, the rejuvenation of the global rig fleet continues as operators and contractors alike seek improvements in equipment reliability and capability. Particularly in deepwater, hope is high that managed pressure and dual-gradient technologies will bring about step-changes in the way wells are drilled.

Finally, the way that operators and drilling contractors work together also appears to be under transformation, with oil and gas companies soliciting increasing input from their service partners. “We’d like to see them take an interest in our well design and take an interest in how we’re actually executing the well because it’s healthy for both of us,” said Derek Cardno, BHP Billiton Petroleum VP of drilling. “We want the drilling contractor pushback.”

By Katie Mazerov, contributing editor

The Emerald Driller, one of four premium jackup rigs owned by Vantage Drilling, is operating in Thailand. The rig features expanded tank capacity and a cantilever reach of 75 ft and can operate in up to 350 ft of water.

Asia Pacific is stepping out of its comfort zone. Long a region with plenty of shallow, easy-to-tap conventional resources, the market has begun a transition, shifting focus to more complex and risky ventures such as deepwater, high-pressure, high-temperature (HPHT) reservoirs and unconventional gas plays in Australia. However, while the prospect of new hydrocarbon sources to replace the diminishing “low-hanging fruit” is heralding exciting long-term growth potential, it also poses challenges of increased costs, lack of infrastructure and a tight labor force. In a survey conducted last year by GL Noble Denton, more than half of industry respondents from the Asia Pacific region cited rising operating costs as their biggest barrier to growth.

High operating costs are already evident in far-flung Australia, where rig availability and mobilization expenses are problematic for operators, said Derek Cardno, vice president, global drilling and completions for BHP Billiton Petroleum. The company will likely have two moored semisubmersibles operating on Australia’s North West Shelf, the country’s primary offshore hub, in 2013.

“It’s an expensive proposition to bring in a rig because we’re transporting it such a long distance,” he said. “That and the work that has to be done to make the rigs acceptable from a safety case standpoint mean operators need to have long-term programs to make those costs worthwhile, or must work with the availability of what is already there.”

Such concerns are not, however, putting a damper on an otherwise healthy and stable outlook for the region, which remains a major gas province that is seeing an increase in liquefied natural gas (LNG) demand from Japan following the tsunami and concerns around radiation effects from the Fukushimi Daiichi nuclear disaster. Malaysia is the area’s most prolific oil producer.

The Osprey is one of three Atwood Oceanics semisubmersibles working off Australia’s North West Shelf. The rig is under contract to Chevron until 2017 in the Gorgon gas field.

Particularly upbeat about near-term activity are drilling contractors, who are ringing in 2013 with strong and rising dayrates, near-100% rig utilization and longer-term contracts. The rig count, particularly in the jackup space, is moving up, and newbuild activity at Asian shipyards is booming.

“Asia Pacific is a diverse and interesting place to operate and a very healthy region right now, with internal energy consumption and gross domestic product (GDP) rates rising in many countries,” said Carey Lowe, senior vice president, Eastern Hemisphere for Ensco, one of the largest and most established drilling contractors in the Asia Pacific market. “A good number of enticing prospects, including deepwater exploration and LNG developments, are expected to materialize in the next few years.” The company has 11 jackups currently working in the region – four in Malaysia, two in Indonesia, two in Thailand, two in Australia and one in Vietnam – and a semisubmersible, ENSCO 8504, operating in Brunei.

Ensco also has three premium harsh-environment jackups from its new ENSCO 120 series under construction at Singapore’s Keppel FELS shipyard. “These rigs are ideal for the deep, heavy-duty LNG gas drilling projects that are either starting up or planned in the region, including Australia’s North West Shelf,” Mr Lowe said. “They are fully automated, with features one would expect to find on a sixth-generation semisubmersible or drillship, including a 2.5 million-lb quad derrick and automated offline pipe-handling systems. We think of the rig as a deepwater equipment package on a jackup.”

The rigs will be capable of operating in 400 ft of water and are being designed for multiwell platforms, ultra-deep gas drilling and extended-reach wells up to 40,000-ft total drilling depth. One rig has already been contracted for work in the UK upon delivery in Q2 this year; the others will be ready in Q4 this year and Q3 2014.

“Operators in this region want high-quality rigs, and we feel we have a good track record for meeting the needs of our customers,” Mr Lowe said.

Atwood Oceanics’ new 400-ft jackup, the Atwood Mako, is working under a contract for Salamander Energy in Thailand. The rig, one of two that were targeted for Thailand’s fast-paced work, features offline pipe-handling capabilities, larger deck space and can rack back large amounts of pipe.

Dayrates on the rise

Ensco also has seen a meaningful improvement in dayrates in the region over the past 12 months, along with higher rig utilization and longer-term contracts. “It is clear from the fourth quarter of 2011 to the last three months of 2012, there has been a fairly significant increase on average for both jackups and deepwater rig rates,” Mr Lowe said. Jackup rates are highest in Australia, averaging in the low $190,000s because of higher operating costs. In other countries, jackup rates range from the mid-$130,000s in Indonesia and Thailand to the high $140,000s in Vietnam to the low $150,000s in Malaysia.

“Rig demand is strong, and 100% of our rigs in the region are contracted,” Mr Lowe continued. “Tendering activity is fairly robust for jackups, and we’ve received a number of inquiries for rigs for deepwater exploration as well.” Key deepwater markets are Australia, Malaysia and Indonesia.

While labor and infrastructure issues pose challenges, Ensco has a long history of employing workers in the countries where they operate. “Employing local workers is something we think we’re good at, and we don’t find it difficult to meet nationalization requirements in the region,” Mr Lowe said.

Vantage Drilling also is expecting regional jackup dayrates to increase due to the extremely tight market. Rates for premium jackups are currently around $160,000 and expected to range as high as $180,000 to $198,000 to match recent Middle East jackup rates for the new premium rigs coming into the market, said marketing manager Ian Craven. “The region’s jackup fleet has recently gone from 48 to 64, but there are a lot of newbuilds coming into the market in the next two years,” he said.

“Some are concerned that these jackups will flood the Southeast Asia market and drive rates down, but in reality, most are likely to find work in other regions. We feel most of the new rigs that remain will find work in the Asia Pacific market, which is looking healthier every day.

“Demand for experienced personnel, however, has stretched local resources with the influx of new-generation rigs and a recent influx of rigs from outside the region brought in to meet high demand,” he continued. “There has been oil and gas activity in the region since the 1970s, and we have a lot of nationals very well trained. But, like the rest of the industry, we are dealing with the big crew change, and contractors are concerned that there aren’t enough skilled workers to service all the rigs coming into the market.”

Vantage is also seeing a trend among operators to venture into deeper and more challenging reservoirs where drilling takes much longer. “Malaysia normally drilled 30-day wells for years, but production there is becoming more complicated, and the country is starting to experiment with HPHT wells,” Mr Craven said. Vantage recently completed a year-long HPHT drilling project in Malaysia for a major independent operator.

Drilling is more straightforward and conventional in Thailand, where wells can be drilled in four to five days. However, reservoirs are relatively small, and wells tend to deplete quickly, so operators have to drill a lot of wells to maintain production, he added.

Atwood Oceanics’ new 400-ft jackup, the Atwood Manta, is working in Thailand for Coastal Energy Company (CEC). The rig is joining the Vicksburg, which has been working for CEC in Thailand since 2009.

A trend of national oil companies gaining traction in the region also has emerged, with companies like Petronas in Malaysia, Pertamina in Indonesia, PetroVietnam in Vietnam and PTT Exploration and Production in Thailand undertaking more development on their own and taking over business from independents rather than engaging in joint venture operations. “This is mirrored by the emergence of new, regionally owned drilling contractors in the jackup market, challenging the traditional US and European contractors,” Mr Craven said.

In Indonesia, home to some 40 operating companies and one of the region’s biggest onshore markets, the tendering system is particularly complex and can take up to a year from tender release to award, Mr Craven noted. Recently, BPMIGAS, the governing body for oil and gas exploration and production in Indonesia, was declared unconstitutional by the Indonesian Parliament, creating further uncertainty.

Vantage has three premium jackups in Southeast Asia – one each in Thailand, Malaysia and Indonesia. All are only two to four years old and capable of operating in water depths of 375 ft with a cantilever reach of 75 ft and modern drawworks and top drive, but are not automated. “Unlike the North Sea, operators in the region prefer jackups that are not fully automated, which they consider slower,” Mr Craven explained. The company has a fully automated rig, the Platinum Explorer, a 12,000-ft capable ultra-deepwater drillship operating in India under a five-year contract for ONGC.

“India has a healthy jackup market and a strong deepwater market, but the jackup market is either ONGC-owned or dominated by Indian drilling companies with relatively new fleets, which makes it difficult for outside companies to compete,” Mr Craven said. Foreign contractors are used for all the country’s deepwater drilling.

KCA DEUTAG has a self-erecting tender (SET) barge in Malaysia, a land rig operating in Brunei and a warm-stacked SET in Singapore that the company is bidding for work in Southeast Asia, said Tony Rodnight, business development manager. “We’re seeing dayrates certainly rising over last year, a trend that is supporting discussions regarding a number of newbuild projects,” he said.

The company’s T-201, a 1,500-hp land rig featuring a skidding system, 700,000-lb hookload and a 14,000-ft drill depth capability, has received the Land Rig of the Year award from Shell for three of the past four years.

Among the challenges in the region is a trend by national oil companies to require local investment. “Operators and contractors want to come into these countries with financial support and technical know-how, but we are being told we need to start working with local companies as potential investors and shareholders,” Mr Rodnight said.

Crew members check readings in the engine room onboard ENSCO 107, operating for PV Drilling offshore Vietnam. Ensco notes that although labor and infrastructure issues can pose challenges in the region, the company does not find it difficult to meet nationalization requirements for rigs working in Asia Pacific.

KCA DEUTAG is also targeting Australia’s LNG market as a key growth area. Specifically, the company is eyeing the LNG market off the North West Shelf and is looking ahead to shale gas opportunities in Australia’s western province. “The coal seam gas market in Queensland requires light-duty rigs, and we don’t see ourselves having any key differentiators there,” he noted.

The biggest challenges in Australia center on infrastructure and labor. The long distances (2,000 miles or more) that rigs must be transported is especially difficult. “In Australia, we’re also competing with the mining industry for labor and equipment needs,” Mr Rodnight explained. “This is the first country where oil and gas is not the No. 1 energy business. That may change in the next five to seven years, but for now, mining and coal development are the primary energy sources.”

Last year, KCA DEUTAG was selected by Woodside Energy, Australia’s largest offshore operator, as one of two drilling contractors to complete a front end engineering design contract for a 3,000-hp modular platform drilling rig for the Browse LNG development project off the North West Shelf. The project, being developed for the Asian LNG export market, is a joint venture of Woodside, BHP Billiton, BP, Chevron and Shell, and is also attracting Japanese investment in the wake of the 2011 nuclear plant disaster.

“All of the major operators have an ongoing or new interest in the continued development of assets on the North West Shelf,” said Keith Jones, recruitment team leader for NES Global Talent, which provides engineering services and specialist staff support for the global energy industry. Last summer, Chevron announced a natural gas discovery by its Australian subsidiary, Chevron Asia Pacific Exploration and Production Company, in the Greater Gorgon area of the region’s Carnarvon Basin. More recently, the company announced the discovery of another well off the North West Shelf, an asset also owned by Shell Development Australia and Mobil Australia Resources.

“There is still an ongoing appetite for renewable energy in the region, but that will be a huge undertaking, so for now LNG is the cleanest and most accessible alternative,” said Marcus Ward, associate director at NES Global Talent.

KCA DEUTAG’s Glen Affric, a self-erect tender (SET) barge, is contracted for work in Southeast Asia. The company also has a SET operating in Malaysia and a land rig in Brunei.

Shale prospects in Australia

Huge shale and tight gas reserves in eastern Australia’s Cooper Basin and in Western Australia also have generated interest. Last year, Santos, one of the largest and oldest Australian operators, began commercial natural gas production from a shale well in the Cooper Basin, which has produced conventional oil and gas since the mid-1960s.

“Following suit with the shale boom in the United States, Australia is beginning to find its own path for shale gas, with projects on the east and west coasts of Australia,” Mr Jones said. “Shale gas is still in the early stages, and as with all exploration in Australia, operators are finding that the cost of hiring a rig is 20% to 30% higher than elsewhere in the world with the additional inflated labor costs. With an increase in drilling throughout the country, rig availability will continue to be an issue. In light of this, we are seeing more rig operators moving into the region with a long-term growth strategy to stay.”

With labor also hard to procure in Australia, most companies have traditionally imported personnel from other regions. But that practice may be changing, due to a push by the government for local content laws that may restrict importation of workers. “Looking ahead, the focus will be on where else in the market we can find these skills. This is where our discipline-specific consultants come into their own by searching the global talent pool but also offering solutions to our clients, such as preparing local college graduates for oil and gas careers,” Mr Jones noted. “It has been important for companies to bring in quality people, but the country also needs a base of trained local people for both the economy and the future of the industry.”

To that end, companies are looking at other industries with the idea of bringing workers into the oil and gas sector and training them with the appropriate skills. Australia’s robust mining industry, for example, offers transferrable skill sets but is also unionized. Offshore operations are more complex, and clients are willing to pay for a fully qualified workforce. “Every major find requires procuring, training and bringing a team on board,” Mr Ward emphasized. “It is essential for operators that they have the A team on projects to ensure they deliver on schedule and on budget.”

The ENSCO 107 is operating offshore Vietnam, where dayrates average in the high $140,000s. Ensco has 11 jackups working in the Asia Pacific – four in Malaysia, two in Indonesia, two in Thailand, two in Australia and one in Vietnam.

With increased operating costs in Australia, it is also critical that the timing for rig deployment be 100% correct, a mandate that has been a focus for NES Global Talent. “We find the best possible team for our clients, make sure they complete every stage of the job on time and then, once the client is satisfied and the work is complete, we work with client and candidate to ensure a smooth transition to the next job,” he said.

Atwood Oceanics has three semisubmersibles operating in Australia – the Atwood Eagle, which is splitting time between Woodside and Apache through mid-2014; the Atwood Falcon, working for Apache through late 2014; and the Atwood Osprey, contracted by Chevron through 2017, said Geoffrey Wagner, vice president, marketing and business development. “We are seeing a trend toward much more difficult drilling for harder-to-access resources,” he said.

“It’s not so much about deeper drilling as it is about ensuring our crews have the training and experience to bring our clients success no matter what they are encountering downhole. Our clients entrust us with their work, and we work diligently to maintain this confidence each day.”

Atwood also has deployed two new 400-ft jackups to Thailand, the Atwood Mako, delivered in August under a contract with Salamander Energy, and the Atwood Manta, working for Coastal Energy Company (CEC). The rigs feature 15,000-psi blowout preventers, offline pipe-handling capabilities, larger free deck areas, 150-person accommodations, 75-ft cantilever reach and can rack back large amounts of pipe, making them ideal for delivering the efficiency needed for drilling quick wells in Thailand.

Vantage Drilling’s drillship, the Platinum Explorer, is working under a five-year contract for India’s ONGC. The ship is designed for water depths up to 12,000 ft.

“These rigs were targeted for the fast-paced work we see in Thailand, where there is an art to drilling safely and efficiently,” Mr Wagner said. “With the right upfront design and pre-job planning, our clients see the true benefits of these great rigs.” The new rigs join the Vicksburg, a 300-ft jackup that has been working for CEC in Thailand since 2009.

Atwood also sees opportunities for two of its three heavy-duty and highly automated drillships in the region – the Atwood Achiever, due for delivery in June 2014, and the Atwood Admiral in March 2015. Both are under construction at the DSME shipyard in South Korea. The rigs, capable of operating in 12,000 ft of water and drilling to 40,000 ft, can be deployed in remote locations and include numerous features that add to the efficiency of drilling and completing complex wells, Mr Wagner noted.

“Post-Macondo, we’re seeing a push toward heavier casing designs, which in turn result in heavier hookloads and other increased stresses to the existing drilling rig fleet,” he continued. “As all of these stresses are interconnected, we are focusing on the design of the entire ship to ensure that we can have an efficient tool for our customers. We have the benefit of being a small company with a great history. Since we have grown organically, we have standardized our equipment, and now benefit from common spares and increased equipment familiarity within our crews.”

Looking ahead, Mr Wagner agrees the industry will be faced with increased challenges in training, new equipment coming online and, especially, maintaining the appropriate level of vigilance with regard to safety and environmental stewardship as Asia Pacific embarks on more challenging fields.

“We will continue to scrutinize our personnel in terms of their training and familiarity with specific equipment and situations,” he said. “We’re going to be bringing out new rigs and putting teams of people together to go into these programs, which are critical to our customer, the host country and the environment, and we want to make sure that we make every operation a success.”

To that end, Atwood has a strong competency assurance program that includes the use of third-party firms to test employees’ knowledge and use of equipment. The program has made a difference in reducing both safety incidents and downtime. “Last year, we had one of our best years ever, a 0.68 total reportable incident rate, and downtime across the entire fleet of about 3.4%,” Mr Wagner said. “As we encounter more and more opportunities in the region and elsewhere that test the technical requirements of our rigs and people, it is our obligation to make sure we do so in a safe and prudent manner.”

By Linda Hsieh, managing editor

In life, sometimes you have to be at the right place at the right time in order to get to that next step. But a lucky break is never enough; it’s what you do once you get that break that will show what you’re really worth and determine where it will take you.

For David Williams, just a few months out of college and in his own words “literally just a kid,” he found himself taking over the contracts administration department for a Galveston shipyard in 1980, simply because he was in the right place at the right time and they needed someone to do the job.

However uncertain of himself, Mr Williams decided to step up to the plate, putting in long hours and six- to seven-day weeks and learning as fast as he could. His hard work paid off, earning an unexpected call about 18 months later that led to a job offer with a drilling contractor, thus kicking off a career in the drilling business.

Now, more than 30 years later, Mr Williams serves as chairman, president and CEO of Noble Corp. He was recently elected 2013 chairman of IADC and is ready to lead the industry association on a broad range of initiatives to improve drilling performance and operational integrity.

Mr Williams’ time in the shipyard business may have been brief, but it was where he fell in love with “big iron” and where he got his first exposure to drilling rigs.

“Whenever a new ship would come in, I’d go down with the ship superintendent, and we’d crawl through the different parts of the ship,” he recalled. “I kind of fell in love with big ships and big engines.”

But this was 1981, and the oilfield was booming while US shipbuilding was in decline. Even at a young age, Mr Williams could sense that he was not in a growth industry.

When a headhunter called Mr Williams on behalf of a company called Salen Protexa Drilling, he knew it was time for a change. “The shipyard I worked for was building a dry dock for our own use, but we built it overseas because they could build it cheaper than we could build it ourselves. If they can build what you can build faster and cheaper, then you’re probably not very efficient,” he said.

Despite hardly knowing anything about the contract drilling business, Mr Williams decided to make the switch. For the next four years, he stayed with Salen Protexa, a Swedish-Mexican joint venture with seven offshore drilling rigs, including four that were under construction. He started out in recruiting and recalls finding mentors in two industry veterans – Darrell Zapp and Jack Smitherman – who taught him about oilfield sales and marketing and offshore operations. “Jack would take me offshore a week at a time. It was the genesis of my career,” he said.

By summer 1985, however, the oilfield boom was no longer. Salen Protexa had been dissolved and its assets sold off. Having been laid off and with bleak prospects for finding new employment in a weak industry, Mr Williams found himself interviewing for a job in a medical-related industry. At one time, he was called in for a third interview but backed out at the last minute because “I just couldn’t get excited about that business … I just couldn’t see myself doing it,” he said.

His passion for the drilling business paid off. Just a week later, Odeco called and hired him on. “Odeco was tough, old oilfield. It was a privilege to be there for a young person because you could learn so much. They were doing so much. We had rigs under construction, which was unheard of in the mid-’80s because the industry was in such bad shape. They really were a pioneer in the industry,” Mr Williams said.

By 1990, he had opened Odeco’s first Houston office to run its US marketing effort, and after Diamond Offshore’s acquisition of Odeco in 1992, Mr Williams continued with the new company in various marketing and operations positions through 2006.

The Noble Don Taylor is one of five newbuild drillships Noble will launch in the next two years as part of its fleet modernization effort.

Noble – new strategy, new fleet

When Mr Williams joined Noble in September 2006 as senior VP of business development, it was a company in transition. Longtime CEO James Day was retiring after leading the company for more than 20 years.

Less than two years later in January 2008, Mr Williams found himself being named chairman, president and CEO of one of the industry’s best-known and most-respected drilling companies. You might say that, just as it was nearly 30 years prior, Mr Williams had been in the right place at the right time. However, the more important question was, now that he had this opportunity, what was he going to do with it?

For one, under Mr William’s leadership, Noble has ordered 14 newbuild rigs totaling over $6.5 billion in investments. “What we’ve done at Noble since I’ve been there is take the company on a different path. Noble had only built two rigs from the keel up prior to 2000. The company had been grown primarily through acquisitions, or we would buy older rigs and upgrade them. But the difference between standard-spec rigs and high-spec rigs have gotten very large nowadays, so we realized we couldn’t do that anymore and still compete at the top of the industry,” Mr Williams said.

In addition to stepping out with the technologically innovative Globetrotter drillships, in 2010 Mr Williams led Noble into the acquisition of Frontier Drilling, which had two Bully-class deepwater rigs under construction that were jointly owned by and contracted to Shell. “With the Shell relationship came a lot of strength in the company, and we really felt like the best way to deploy the cash was to reinvent the fleet. So we started on this program to transform the fleet,” Mr Williams said.

Starting with deepwater rigs, Noble committed to two more drillships at the Hyundai shipyard in South Korea with options for two more. That was followed by commitments for two jackups at Singapore’s Jurong shipyard with options for four more. Ultimately, all options were exercised.

“Newbuilds are hard on an organization just because it takes so much time, effort and dedication, but we have such good loyalty with our workforce, and we’ve put together project managers we have a lot of confidence in,” Mr Williams said. “It’s not going to be without hiccups, but as we’re transforming our fleet we’ll also be rejuvenating it. Noble will come out of this looking like a different company, a much more technologically advanced company.”

Mr Williams believes this fleet makeover will be critical for Noble’s success going forward, particularly in the deepwater segment. “This industry has grown up with the rest of the world. We’re a lot more sophisticated. Odeco drilled Ekofisk with a first-generation semisubmersible, but they’d laugh at you in Norway if you tried to bring something in there like that now. The high-tech wells we’re drilling today in deepwater require much more sophisticated kit, and frankly the risks are much higher. Some of the older rigs may still be running, but with the big bores and deep waters, you need high-spec rigs to drill efficiently.”

The Noble Scott Marks, one of three JU2000N jackups constructed by the company, will join six new JU3000N units currently under construction, significantly high-grading Noble’s jackup fleet in the coming years.

Competency, safety top priorities

Amid the rig-building frenzy is another frenzy – for experienced and competent personnel. Industry realizes that no matter how great its rigs are, they won’t matter if we don’t have the right people to man them.

“Technically speaking, there’s not much difference between a DP3 sixth-generation deepwater rig and the space shuttle. They’re both very complex kits. To ensure we can operate those competently and efficiently is a critical part of what we’re doing, and we’re putting systems in place to develop that capability,” Mr Williams said.

Noble hired 1,400 people in 2011, approximately 1,100 in 2012 and is slated to hire an additional 1,000 people in 2013. “The ramp-up in personnel is not just about putting bodies on the rig. It’s making sure those bodies are competent to do the jobs that we require. Today we have more than 40 trainee subsea engineers working as extras in our fleet all over the world. We’ve got extra rig managers, extra drillers – so that we can have competent people ready to step up when those rigs come out of the shipyard.

“We try to put a crew on the rig as early as six months prior to delivery and even earlier for some of the key people. The goal is that by the time the rig rolls out, the crew is a team. They operate as a team safely and efficiently,” Mr Williams said.

Safety is not negotiable, he continued, which is why crew competency is paramount. The way that industry evaluates workplace safety is also evolving, with Noble now placing less emphasis on numbers like lost-time incidents and recordables.

“They’re just not statistically meaningful, so we’re looking at HIPOs and severity potential,” Mr Williams said. “If a bolt falls out of the derrick and hits a guy on the finger, that’s the same statistically as if a guy sets a load down on his finger. But the severity potential of the bolt falling is much higher, and it was just luck that someone wasn’t killed. We don’t trust in luck. We’re spending much more time looking at stuff like that than we are at just statistics, being much more focused on process safety.”

Another change Mr Williams would like to see in the industry is for contractors to get more involved in the wells they’re drilling. “For a while now, contractors have let operators make all of the decisions about the well. It was a mentality of ‘I’ll run the rig and you run the well.’ But I think that drillers need to get back involved because it’s our rig and our people. We have to maintain control of the situation. This means we have to be just as competent downhole as the operators. If the well starts acting up, we have to make sure the driller has the knowledge, the nerve and the support to say no to the operator. He needs to know what to do and to do it without asking.”

Management attitude will be key to providing a supportive environment for drillers so he can act with confidence, and Mr Williams also noted that the IADC KSA project will be a good starting point to ensure rig personnel are equipped with the right knowledge, skills and abilities to make such important decisions. “The KSA project will establish what the minimum competencies are for critical positions on rigs. They will be different for a driller on a straight hole in West Texas versus a driller in 10,000 ft of water, but there are a lot of similarities if that well starts flowing.”

As chairman of IADC for 2013, Mr Williams notes that although the association continues to be the only global forum that deals solely with drilling contractor issues, he would like to see more operator involvement on a broader level. “IADC should be the leading authority on how we drive competence in drilling hands, and if operators want input into that, they need to get involved. IADC’s role is to support and further the goals of drilling contractors, and that has a direct impact on other industry players, including operators. This is the forum to table those ideas,” he said.

The association is also in transition, he noted, moving in 2012 under the leadership of new president and CEO Steve Colville. “Steve’s doing great so far. IADC has taken on some good initiatives under his guidance,” Mr Williams said.

“The Executive Committee is taking a hard look at IADC for the first time in a very long time. Are we on the right path? Are we doing the right things? Competency means different things to different people, and there are different issues we’re facing offshore and onshore. But all of those issues of competence are going to permeate throughout the industry. Everybody’s going to insist on some level of accreditation, and IADC is the forum to get that done. I think the agenda IADC is pushing is the right one.”

Click here to view the embedded video.

Baker Hughes’ IN-Tallic disintegrating fracturing balls disintegrate over time for unimpeded production in unconventional shales.

Fracturing, stimulation advances fuel production boom, reduce environmental impact; next-gen innovations focus on increasing overall, IP rates

By Katie Mazerov, contributing editor

It’s no secret that unconventional shale production is booming in North America, and the news keeps getting better as industry continues expanding into new oil and liquids-rich plays. So bullish is the outlook for shale oil, the International Energy Agency (IEA) has projected that the US will overtake Saudi Arabia as the world’s largest oil producer by 2020.

“When it comes to unconventional shale fracturing and completions, the US is the center of the universe,” said Rob Fulks, director of shale resource projects for Weatherford. “Not every country is blessed with these great expanses of shale that hold tremendous potential to meet global demand for increased oil and gas.”

Still, challenges remain. Recovery rates remain in the single digits, considerably lower than in conventional reservoirs. Wells also see steep decline rates after initial production (IP). This is driving operators and service companies to continue developing technologies to boost recovery and improve economics and efficiency while at the same time reduce the environmental footprint and comply with increasing regulations.

Whereas the drilling side of the business cracked the horizontal drilling code that made unconventional production possible, the completion side of the equation still has work to do beyond multistage fracturing. Over the past 10 to 12 years, industry has learned that the geologic variability of shale reservoirs means production is inconsistent and uneven. To that end, the focus is now on finding solutions to improve monitoring, better understand and connect to the reservoir, identify and target the sweet spots, enhance fracturing and stimulation and proppant distribution and even re-fracture to boost rates in older, nonproductive wells.

Whiting Petroleum uses advanced open-hole technology to fracture a well in the Sanish formation in the Williston Basin. Whiting has completed nearly 500 wells in the basin’s Bakken and Three Forks plays, all with an open-hole design that takes advantage of natural fractures in the reservoir.

“Ultimately, improved recovery, both overall and IP rates, is what we’re looking for,” said John Paneitz, senior operations engineer for Whiting Petroleum, one of the largest operators in the Williston Basin’s Bakken and Three Forks plays, which is characterized by complicated geology and extended-reach laterals with measured well depths as long as 20,000 ft. “Overall recovery is low in shales because the reservoirs are generally poorer quality than conventional reservoirs, which have higher-quality rock that allows the hydrocarbons to flow much better. We’ve picked the low-hanging  fruit; today there are more reservoirs that are poor quality, and we’ve gotten better at accessing them.”

Halliburton’s CleanWave mobile water treatment service enables treatment at the site for recycling produced and flowback water.

Looking to capitalize on multistage completion technology, operators have increased the number of stages and fractures to access more rock. “We are now running 40 stages, shrinking the distance between each of those stages down to less than 300 ft,” Mr Paneitz said. But even that strategy has limits. “We saw significant results when we went from 10 to 20 stages and some improvement when we went from 20 to 30 stages,” he said. “But  we’re starting to see diminishing returns on 40 stages because when we add more stages, we also increase the cost.”

Whiting has drilled nearly 500 wells in the Williston Basin, all with an open-hole design that uses swell packers for annular isolation. “We like open-hole technology because we can take advantage of the natural fractures,” Mr Paneitz said. In the vast majority of those wells, frac sleeve technology, as opposed to the conventional plug-and-perf method, is used for fracturing.

The sleeves, containing specially designed ball seats, are shifted open with frac balls to expose ports for fracturing. Advances in sleeve design have made the technology possible in wells with 30 or more stages. Using the open-hole packer and sleeve completion design, Whiting has seen both improved economics and a reduction in days on location, which translates to HSE benefits and lowered risk, he noted.

Baker Hughes’ DirectConnect ports allow the well to be fractured in the sweet spots for optimum recovery. Increasing connectivity with the payzone has been an important driver behind the latest generation of the company’s FracPoint multistage fracturing technique for open holes.

Looking ahead, Mr Paneitz believes fluids and fluid surfactants that improve recovery of oil from rock will be the next big breakthrough. Farther down the road is the idea of refracturing, which he says cannot be done with the same multistage design. “At this point, we would have to do a ‘Hail Mary’ operation and hope the fracture goes where we think it should.”

Four years ago, Whiting installed reclosable frac sleeves as a long-term experiment with the idea of refracturing the well or wellbore sections to reestablish production at a later date. The operation has not been carried out, primarily because the company is focused on new production. “When there is a well on every corner, which we’re quickly hitting, then we can go back and revisit older wells to refracture,” he said.

Among the ongoing challenges the industry is beginning to tackle is the inconsistent production resulting from the intense variability of unconventional plays. “The industry has done a fantastic job of improving the cost of these wells, which we can drill and complete very quickly,” said Kyel Hodenfield, vice president, unconventional resources for Schlumberger. For example, to reduce costs and improve efficiency in cemented plug-and-perf operations, the KickStart pressure-activated  rupture disc valve is being installed as part of the casing string in the first stage, or toe, of many wells to allow for stimulation without the need for coiled tubing or other intervention.

While driving down costs is important, however, operators really want to improve the cost per unit of production. “That means eliminating bad wells by locating the sweet spots and then optimizing the completion,” Mr Hodenfield said, citing IHS data indicating that as many as 60% of the wells in a given play are uneconomic, due to the heterogeneity and variability of the reservoir.

“Operators are often surprised that what they thought was going to be a productive well actually is not.”

Schlumberger is integrating seismic technology with core and wireline logging data from vertical pilot wells to study the properties of the reservoir to identify the sweet spots, which is a combination of reservoir quality and completion quality parameters. “With this integrated reservoir-centric workflow approach, we’re measuring effective porosity, pore pressure, natural fractures, hydrocarbon saturation and whether the formation will be receptive to a fracture filled with proppant,” Mr Hodenfield explained. “Many reservoir sections do not have the proper composition, stress or texture that produces a viable fracturing system.”

Mangrove software’s unconventional fracture model (UFM) uses pre-existing natural fractures and a mechanical earth model to simulate fracture geometry. Microseismic data is superimposed over the UFM results for comparison.

Due to the variability, the completion effectiveness also varies along the wellbore. “We have run production logs in hundreds of horizontal multistage wells and have identified inconsistent production, with more than 40% of the perforation clusters and 20% of the stages not contributing to production,” he continued.

To achieve more consistent results, the Mangrove reservoir-centric stimulation design software uses the integrated workflow approach to devise a seismic-to-simulation model that designs a complex fracture ahead of time by taking into account the reservoir geology and geomechanics and properties of the rock.

“We can’t assume these reservoirs are homogeneous,” he said. “Rather than place perforation clusters every 100 ft, which is the way many wells have been addressed, we have proven it is more productive to engineer the completion and vary the stage lengths based on the composition and fabric of the rock and then locate the perforation clusters where stresses are similar to achieve a simultaneous breakdown.”

Schlumberger’s HiWAY service creates infinite fracture conductivity in vertical and horizontal wells.

Schlumberger’s HiWAY flow-channel hydraulic fracturing service increases production while significantly reducing water and proppant. Combining chemistry, fibers and a pumping schedule, proppant treatment is pulsed while the fibers are pumped continuously. The fiber keeps the proppant together in pillars, creates channels and then dissolves into fluid after the operation is completed.

The technology is being used in most plays on nearly a third of the company’s hydraulic fracturing jobs. In the Eagle Ford, wells using the technology showed a 32% production increase over wells completed with crosslinked gels after 90 days and a 37% increase after 250 days. Compared with slick water, production rates using this technology showed 67% and 87% increases after 90 days and 250 days, respectively.

“With HiWAY we reduce the amount of proppant by about 40% and eliminate up to 60% of the water. Over the past 18 months, the reduction of water and proppant has already eliminated over 40,000 transports to and from the well site,” Mr Hodenfield said.  “We want to do more with less – less proppant and water, fewer people and trucks.”

Halliburton’s CleanStream mobile unit uses ultraviolet light rather than chemicals to control bacteria in water used for hydraulic fracturing operations.

Sustainable stimulation

While recovery, efficiency and economics are priorities for operators, reducing the environmental impact while improving sustainability of the stimulation process remains critical. Halliburton’s CleanSuite portfolio of production enhancement technologies for hydraulic fracturing and water treatment is a three-tiered approach to addressing that challenge, said Nicholas Gardiner, strategic business manager, production enhancement. The CleanStim fracturing fluid, 100% sourced from the food industry, reduces chemical exposure risk at and below the well site; the CleanStream service uses ultra-violet light instead of chemical biocides to control bacteria; the CleanWave system recycles water through electro-coagulation, minimizing waste and the use of chemicals.

While the shift from gas production to oil has not had a major impact on completion methods, it has resulted in a swing away from water-fracturing techniques to gel and crosslinked gel techniques. “The move to oil increases the requirement for a highly conductive fracture, and we’re seeing an emphasis on surfactant technologies and gels with less residue,” Mr Gardiner said.

Last year, Halliburton introduced PermStim, a robust fluid system to improve fracture connectivity using a derived natural polymer rather than guar.

Among other basins, the system was deployed in the Eagle Ford play, in a fracturing treatment in a 6,050-ft horizontal well section at 10,897-ft vertical depth with a bottomhole temperature of 280°F, where the operator saw a 20% increase in average initial production. It has since been used successfully in more than 100 wells, primarily in the Williston, Denver-Julesburg and Green River basins at temperatures up to 300°F bottom static temperature.

Another challenge in the low-permeability shale basins is proppant distribution. Halliburton’s AccessFrac suite of stimulation services improves proppant distribution in multizone completions and includes features designed for refracturing treatments, infinite conductivity and enhanced development of complex fracture networks. “This ensures operators that multiple perforated intervals can be fracture-stimulated at the same time, without inserting isolation plugs between intervals,” Mr Gardiner said.

Software technology relevant to improved recovery includes Halliburton’s new Knoesis service that interprets microseismic knowledge in real time and integrates that information into the fracture design during the fracturing operation. “This involves two disparate technologies talking to each other in real time – applying microseismic or monitoring technology into the pumping schedule while we can actually use it to optimize recovery,” said Ron Hyden, Halliburton’s technology director for production enhancement.

Looking ahead, industry will continue to push for incremental improvements in recovery rates, he believes. “The single-digit recovery rates have not been on the industry radar because we’ve been able to get by with them. But as operators recognize that low recovery rates are not acceptable, they are pushing to improve the economics. We need to look to the science community to determine what about shale rocks makes recovery so marginal, versus classic sandstone or carbonate formations.

“Shale has some unique characteristics that will make it necessary for us to make modifications in our chemistry and production methods,” he continued. “I anticipate that our laboratories will do more work in the development of geomechanics and technologies often referred to as digital rock, where we analyze the formation at a micro level to better understand the mechanics that drive fluid movement.”

Increasing connectivity with the payzone has been an important driver behind Baker Hughes’ latest generation of its FracPoint multistage fracturing technique for open holes. The latest design allows a single ball to open up to five sleeves per stage to direct fracturing treatment into the formation. Each FracPoint MP sleeve includes eight DirectConnect ports placed 45° around the circumference of the sleeve.

The system can be used as an alternative to the plug-and-perf method in up to 17 stages per well, eliminating the need for cementing the liner in place.

“The system was developed based on information we’ve received from reservoir analyses indicating that by controlling the initiation point of fractures in some wells and reservoirs, we can gain significant improvement in the productivity of the well,” said Ed Wood, product line manager for unconventional completions at Baker Hughes. “We start by understanding the reservoir, drilling the well in the right place, gathering data along the wellbore to identify the sweet spots and then placing the sleeves in the sweet spots so that when we fracture the well, we gain the best opportunity for the most recovery.”

The system allows as many as five sleeves to be opened with one IN-Tallic fracturing ball, which disintegrates over time, he explained. When the ball is dropped, it passes through the sleeves, with the first four sleeves subsiding into a recess to allow the ball to land in the final fixed sleeve. When the sleeves are opened, hydraulic pressure launches the DirectConnect telescoping ports into the formation with up to 15,000 lbs of force.

The impact of the ports into the formation changes the near-wellbore stresses and creates the path of least resistance in the formation, which helps control where the fracture initiates, Mr Wood continued. This allows the operator to directly influence where the fractures are, rather than the fracturing occurring at the naturally weak points in the formation.

These sleeves not only allow multiple initiation points per stage but also the accurate placement of the fracture treatment, ultimately giving better connectivity to the reservoir.

“When compared to cementing with plug-and-perf operations, this method can deliver significant time and cost savings for operators,” Mr Wood said. “Along with directly targeting the optimum places to fracture, we’re getting more sleeves and hundreds of connections to the reservoir with fewer balls, which have the added feature of disintegrating with time.” The system has so far been deployed successfully in North America, including Alaska. “We are evaluating those operations and looking at how this technology can be best used internationally,” he added.

Looking ahead, Mr Wood believes unconventional completions will continue to increase in North America and blossom in other areas globally.

“We believe that by using reservoir models that integrate log-derived, near-wellbore geomechanical and petrophysical properties from calibrated seismic data, operators can optimize well placement and completion design earlier in the reservoir life cycle for more efficient construction and improved recovery,” he said. “Technology combined with field experience will lead us into the new reservoirs.”

Top: NSC-Tripoint’s ball-dropped cementable frac sleeve can be used in multizone operations where cement is either preferred or required due to the type of formation. The system was designed to reduce the amount of water and horsepower needed on location. Bottom: The STIMMAX completion system allows operators to open up to five valves per stage, with five points of entry, all manipulated with one ball. Suited for both cemented and open-hole applications, the method effectively stimulates an entire horizontal wellbore, up to 20 stages.

Cementable Solutions

NSC-Tripoint, which provides downhole completion tools and services for all the major US shale plays, has expanded its STIMPACT portfolio with a ball-dropped cementable frac sleeve (CFS) for multizone operations where cement is either preferred or required due to the type of formation.

The STIMPACT CFS replaces the conventional plug-and-perf method, the stimulation technique still used in 75% of unconventional, horizontal wells, explained Ryan Henderson, operations manager/business development – unconventional completion services for NSC-Tripoint.  The system enables one point of entry for each zone; the ball is dropped from the surface, landing on the frac sleeve ball seat. The frac sleeve will then be manipulated by differential pressure, allowing proppant and pad, acid, slick water, N₂, CO₂ or the applicable stimulation option to enter the formation to begin the stimulation process.

“Customers needing cement for isolation to help pinpoint and project fracture placement can use this technology to increase their efficiency, reduce the amount of water required and reduce the amount of time they need horsepower on location, which is a huge part of the spread costs,” Mr Henderson said. “It also provides greater accuracy in targeting the sweet spots and effectively draining the formation.”

The technology was successfully used in the completion design of a well in the Marcellus play, deployed in the first five stages of a 14-stage hybrid system.

The company’s STIMMAX completion system for cemented and open-hole applications, commercialized in the last year, allows operators to open up to five valves per stage, with five different points of entry, all manipulated with one ball. The method effectively stimulates an entire horizontal wellbore, up to 20 stages, allowing for continuous fracturing and increasing recovery with fewer balls.

“This technology represents a big step forward for the industry by providing the machinery and advanced rubber for seals and O-rings to deliver an effective product that will successfully stimulate the formation, save time and cost, and provide more reliability and also provide limited entry, which is a preferred stimulation method,” Mr Henderson said.

Whereas a 20-stage operation using the conventional plug-and-perf method would likely require seven to 12 days to bring a well on production, both the STIMPACT CFS and STIMMAX systems can reduce that time to one to three days, Mr Henderson noted.

“We’re evolving to provide the technology and solutions our customers want, reducing service costs and helping operators gain a return on their investment in a third of the time.”

Weatherford’s i-ball system uses a one-size ball, rather than graduated ball sizes, to open an unlimited number of seats, which ultimately disappear. The technology maintains internal diameter and eliminates the need to mill out the balls.

Eye on the ball

Weatherford’s ZoneSelect open-hole completion portfolio has been enhanced to include the new i-ball multizone frac sleeve that optimizes production, reduces operational costs and increases efficiency in shale wells. “Most of the efficiency and production improvements we’re looking for today are on the completions side,” said Eric Blanton, global product line director for Weatherford’s Lower Completions division.

The i-ball technology uses a one-size ball, rather than graduated ball sizes, to open an unlimited number of seats, which ultimately disappear. “This opens up new doors for customers needing 40 zones because the internal diameter doesn’t need to be reduced with each sleeve and because it eliminates the need to mill out the balls,” Mr Blanton said.

Initially designed for the Bakken market, the technology has been used successfully in a number of extended-reach wells in the play but can be deployed in both open hole and cemented wells, he noted. Weatherford plans to launch the sleeve in 5 ½-in cased wells and has also tested the system for 4 ½-in casing.

Weatherford fracturing service technicians put the final high-pressure components together for a shale completion about to be pumped. Along with new technology, Weatherford believes that significant advances are likely to emerge from the ability of service companies to finally access long-term production logs that are providing important lessons for the industry.

The ZoneSelect MASS frac sliding sleeve provides an alternative to plug-and-perf operations, particularly for cemented wells. The sleeve can be placed between isolation packers in multizone completions, or cement can be used for isolation.  “This type of completion comes closest to mimicking a plug-and-perf application because when we drop one ball across the interval, it opens multiple sleeves and allows us to fracture across that interval through all the sleeves at the same time,” Mr Blanton explained.

“It is particularly beneficial when fracturing across multiple perforation clusters to create a transverse fracture.” The system is being used in the Eagle Ford play, where cased-hole completions are still the preferred method, as well as in the Marcellus region and Canada.

For operations requiring coiled tubing (CT) stimulation, the ZoneSelect CT system can open unlimited zones with isolation devices, also eliminating the need for milling. The technology, which monitors pressure along the CT string and facilitates real-time adjustments for each zone, is being used in the northern Bakken region in Canada and will be deployed for applications in the Eagle Ford play, Mr Blanton said.

But along with new technology, significant advances are likely to emerge from the ability of service companies to finally access long-term production logs that are providing important lessons for the industry moving forward. “Up until now, we’ve seen a fairly geometric pattern in these completions – same size stages with uniform distances between perforation clusters,” Mr Fulks said. “But, we’re learning that these operations aren’t nearly as efficient as they need to be because we didn’t take the time to place perforations at the most potentially productive intervals to begin with. Now, we’re starting to look outside the box by studying our logs and cuttings analyses and placing perforation clusters where they have the highest probability of success. We’re beginning to see significant improvement in overall performance simply by putting a little bit of science behind what we do.”

KickStart, Mangrove and HiWAY are marks of Schlumberger.

FracPoint, FracPoint MP, DirectConnect and IN-Tallic are trademarked terms of Baker Hughes.

STIMPACT, STIMPACT-CFS and STIMMAX are trademarked terms of NSC-Tripoint.

ZoneSelect and i-ball are registered terms of Weatherford.

By Katherine Scott, editorial coordinator

A Newfield Exploration reservoir engineer stands in front of H&P FlexRig 389, operating in the Eagle Ford, where Newfield is drilling its first 10,000-ft lateral. The company says it is averaging 11,000-ft laterals in North Dakota’s Williston Basin. Image courtesy of Newfield Exploration

Trumpets or fireworks may be absent in celebrating substantial industry growth as 2012 concludes, but that’s no matter. Over the past 12 months, industry solidified its footing after facing significant regulatory and economical challenges over the previous couple of years. And although industry is ending the year with a slowdown  in available rig work, strong oil prices remain a welcome sign for a positive outlook for 2013.

“Right now we’ve gone down in rig utilization. There’s no doubt. The numbers substantiate that for the whole industry,” John Cromling, executive vice president for Unit Drilling, said. “But I think it’s a short-lived downturn, and I think 2013 is going to be good.”

Earlier this year, Drilling Contractor reported in its March/April issue of high rig utilization, rising dayrates and a general market boom in US land drilling. Since then, however, the market has lost some steam. Operators reevaluated budgets against natural gas prices and seemingly softening oil prices, and the call for drilling rigs weakened. As a result, contractors have seen their business slow and expect it to stay that way through the end of the calendar year.

“In the late June time frame, WTI oil prices dipped just very briefly below $80 a barrel. That was a bit of a wakeup call for everybody. Budgets were scrutinized  and operators recognized that if they maintained current rig activity, they were going to outspend their budget, so some rigs were released,” John Lindsay, president and COO of Helmerich & Payne, said.

The transition from dry gas plays to liquids-rich in the US endured, however. Growth potential in key areas such as the Eagle Ford, the Permian Basin and emerging plays like Ohio’s Utica Basin have garnered a confident picture of 2013.

“There’s a huge disparity between oil and gas prices, and our view is that we’ll be in a lower gas price world for longer,” Stephen Campbell, vice president of investor relations for Newfield Exploration, said. “For next year, I see a continuation of the same theme where all the money is going into oil and liquids-rich plays.”

However, amid a general optimistic attitude for 2013, an industrywide feeling of uncertainty remains – uncertainty in the global economy, uncertainty in global and regional politics, and uncertainty in the global market. Although oil prices remain relatively high at about US $85/bbl to $95/bbl, natural gas prices continue to hover around $3/mcf to $3.50/mcf, causing some to wonder if such continued weak pricing may lead to a repeat of the 2008 downturn.

Helmerich & Payne, Unit Drilling, Trinidad Drilling, Pioneer Natural Resources and Newfield Exploration capture their experiences of 2012 and general outlook for 2013.

H&P FlexRig 500, a FlexRig5, operates in the Marcellus. The H&P fleet, supported by its advanced-technology FlexRigs, currently has approximately 236 of its 285 US drilling units in operation; the rigs are predominately 1,500-hp, AC-drive rigs that typically target a range of 14,000- to 22,000-ft drilling depths.

In 2012, the migration that began more than a year ago from the drier gas basins to liquids-rich plays in the US continued, with some companies moving operations completely to basins and plays such as the Permian and the Bakken. Within that shift, however, is emerging a sub-trend toward higher-quality liquids.

“When we say ‘liquids-rich,’ it may range from a low percentage of liquids in one part of the basin to a high percentage of liquids in another part of the basin,” Mr Lindsay said. “What we’ve started seeing now are rigs transitioning from the lower end of the natural gas liquids to black oil basins or higher-quality oil and liquids. Customers are looking to target the commodity that’s going to bring them the highest prices per barrel.”

Customers also are looking for the highly efficient AC-drive rigs, he said. H&P estimates that there were approximately 1,750 land rigs working in the US as of late September, and only 30% are AC-drive rigs, compared with 31% SCR and 39% mechanical rigs. “Many of the rigs that are available are not the rigs that customers want,” Mr Lindsay said. “We continue to see this sideways to slightly down transitioning of the rig count because customers are high-grading their rig fleets. Some of the older, less efficient, less safe rigs are continuing to stack, and this replacement is not a ‘one for one’ trade.”

When asked about the outlook for 2013, he added: “At the first of the year, if the WTI oil price remains in the $80/bbl to $95/bbl range, then activity should improve, and the best rigs, the AC rigs, are going to be snatched up first. … Those rigs should also be able to continue to command a performance premium in the marketplace, assuming the commodity prices hold.”

The H&P fleet, supported by its advanced-technology FlexRigs, has approximately 236 of its 285 US drilling units in operation; the rigs are predominately 1,500-hp, AC-drive rigs that typically target a range of 14,000- to 22,000-ft drilling depths. The Eagle Ford is the most active basin for the company, where approximately 90 of the company’s rigs are employed and where Mr Lindsay predicts another strong market in the coming year.

Three FlexRig3s work in Oklahoma.

The company also has 17 newbuilds under way that will be delivered at a pace of about four rigs a month until the end of 2012, followed by four rigs to be delivered in Q1 2013. All will be AC-drive FlexRigs built against term contracts of three to five years. Twelve rigs are going to the Eagle Ford shale, three will be sent to the Permian Basin, one is going to the Fayetteville shale and one will go to the Bakken. Outside the US, H&P also has 16 FlexRigs operating across Colombia, Argentina, Bahrain, Abu Dhabi and Tunisia.

Looking toward the industry’s growth potential in 2013, Mr Lindsay commented that marketplace uncertainty is likely to remain a lingering concern and may impact drilling budgets. “Companies are going to be less likely to invest and have more aggressive drilling budgets. A global economic slowdown is going to reduce the demand for oil and gas products, which is going to have a negative influence on price. In turn, that’s going to decrease the number of wells drilled,” he said. Still, he urged, the industry can’t simply stop spending money. “You’ve got to be prepared to spend through the ups and downs. Downturns are opportunities for companies to prepare for the next up cycle.”

Of all US onshore wells being drilled, it’s believed that approximately three-fourths are now horizontal. It’s therefore no surprise that Unit Drilling has seen a high 85% utilization rate of its 1,000- to 1,700-hp rigs, which are typically best suited for horizontal wells. “That’s what is the most popular by far,” Mr Cromling said. And, yet, he points out that the classification of rigs by horsepower is “almost a meaningless number anymore with horizontal drilling.” Mr Cromling believes that with the right mud pumps, top drive and pit system, the rig’s horsepower rating can become insignificant because “the pit system and pumps are key to

Above and left: Unit Drilling’s Rig 201 is currently drilling in Cameron Parish, La., for Chevron. Unit Drilling has seen a high 85% utilization rate for its 1,000- to 1,700-hp rigs, which are typically best suited for horizontal wells. “That’s what is the most popular by far,” said John Cromling, Unit’s executive VP, although he believes that with the right mud pumps, top drive and pit system, the rig’s horsepower rating can become insignificant. Images courtesy of Unit Drilling.

how you drill a horizontal well.”

Lower-horsepower rigs, in the range of 700 hp to 900 hp, are beginning to find increased use in emerging marketplaces, he continued. Recent finds in the Mississippian play in north Oklahoma and southern Kansas, in particular, have increased the drilling of shallow horizontal wells. “This trend toward shallower horizontal wells really hasn’t even reached its full potential,” Mr Cromling said. “Who knows how many more of these shallow plays there could be? There’s a lot of old producing areas that have not been drilled horizontally that lend themselves to be good candidates.”

He believes that, due to the size of the geological area of the finds, the shallow horizontal drilling trend could last for the next decade. “You’re not talking about a little pod somewhere. You’re talking about hundreds and hundreds of square miles of geographic area, so your potential for a high number of wells is great.”

To drill these massive numbers of horizontal wells, contractors have honed in on high-specification rigs, pushing industrywide drilling efficiency to the best it’s ever been, Mr Cromling believes. In turn, this means that fewer rigs are needed to drill the same footage.

This year alone, Unit upgraded and refurbished 10 rigs with top drives, more horsepower and new pumps. “If we hadn’t refurbished those rigs, they probably wouldn’t be working. That’s how critical it is,” Mr Cromling said. Going forward, he believes horizontal drilling will continue to drive a large number of additional pump and mud system upgrades.

Similarly, upgrading their rig fleet to bi-fuel systems, Unit has expanded the efficiency of its rigs by allowing them to predominately run on natural gas when available and practical. “Using natural gas today is the best fuel you can use; it’s the cheapest, the cleanest and the most available.”

Above and left, top: Unit Drilling’s Rig 201 is currently drilling in Cameron Parish, La., for Chevron. Left, middle and bottom: Unit’s Rig 322 is operating in Sublette County, Wyo., for QEP. New areas of activity continue to pop up in the US, Unit executive vice president John Cromling said. However, instead of creating whole new marketplaces for rigs, operators are more often choosing to move rigs from one play to another. Images courtesy of Unit Drilling.

Still, although upgrading rigs can support higher rig utilization numbers for contractors, overall contract length and dayrates have come down for the industry, Mr Cromling said, adding that it’s primarily newbuild rigs that are securing long-term contracts these days. Because the current marketplace is weak, operators have their choice of rigs. “If they don’t have to make a long-term commitment to get a rig, then they’re not going to,” he said. “The market needs to pick up a lot in 2013 to where operators feel like prices are trending upward. Then they’ll be receptive to locking in for a longer time period.” And with the downward trend in activity, dayrates too have followed, he said. “It’s just a fact of life.”

New areas of activity do continue to pop up in the US, Mr Cromling said, such as Ohio’s Utica play. However, instead of creating a whole new marketplace for rigs, operators tend to move rigs from one play to another, such as from the Marcellus to the Utica. “The Permian’s still hot, the Eagle Ford’s still hot, but it’s not adding a greater number of rigs. They just move from one place to another, which is not bad, but it’s not as exciting as if we’d gone from 2,000 rigs to 2,500 rigs,” he said.

Unit is most active in the Bakken, the Mississippian play, western Oklahoma and the Texas Panhandle, with 127 US land rigs that are being operated at 56% utilization. The company also added three 1,500-hp newbuilds this year. One deployed in May to North Dakota on a three-year contract with Kodiak while the other two were delivered in January and May for a three-year contract with QEP in Wyoming.

Trinidad Drilling’s Rig 138 (above) and Rig 137 (left, top) operate in the Eagle Ford, where the company has the highest concentration of its North American land rigs, at 20 units. Left, middle: Trinidad’s Rigs 56 and 57 were constructed at the company’s manufacturing facility in Nisku, Canada. Rig 56 is now working in British Columbia, and Rig 57 is operating in oil sands south of Fort McMurray. Left, bottom: Trinidad Rigs 48 and 50 conduct pad drilling in northeastern British Columbia. The contractor says Canada has taken advantage of the pullback in US rig demand to push for more rig performance. Images courtesy of Trinidad Drilling.

For Trinidad Drilling, one of the biggest lessons learned from the 2008 downturn was the benefits of take-or-pay contracts, “where a rig is contracted, generally a newly constructed built-for-purpose style rig, for a guaranteed number of days per year at a set dayrate based on the total number of years they’re willing to commit to the rig,” Lyle Whitmarsh, CEO of Trinidad Drilling, said. In the fickle drilling market, contractors like Trinidad have increasingly sought out these types of contracts to guarantee returns on investment for newbuild rigs.

“Because we have take-or-pay style contracts, we’re not having to react to short-term spikes,” Mr Whitmarsh said. “Our rigs are continually working; 60% of our fleet is on long-term contract.”

Still, although term contracts are helping Trinidad to manage the spikes and valleys of commodity prices swings, Mr Whitmarsh acknowledges that these ups and downs will continue to challenge his company as well as the overall industry over the coming year. A firm market rebound in 2013 will be directly dependent on stability in commodity pricing, he believes.

Besides leveraging take-or-pay contracts, Trinidad also has designed its fleet to be able to move between a number of plays and react quickly to shifts in operator budgets. “As we move into 2013, we want to be able to respond and assist our customers when the global economy puts pressure on their operations,” Mr Whitmarsh said. Of its total fleet of 129 land drilling rigs in the United States, Canada and Mexico, approximately 85% to 90% are drilling for oil or liquids-rich natural gas, and the highest number of them are in the Eagle Ford, with 20 rigs.

“It would take a fairly fundamental shift in gas commodity pricing to see an incremental number of drilling rigs move back to the gas side,” he said.

In 2012, Trinidad constructed four newbuilds, all built-for-purpose, AC-drive rigs ranging from 1,000-hp to 1,500-hp for Canadian operations. Mr Whitmarsh explained that Canada, in particular, has taken advantage of the pullback in US rig demand to push for more performance up north. “There seems to be more openness in Canada at this time for certain style of rigs. They’re getting themselves in a position where they can contract a newer-style rig to start capitalizing on their efficiencies.”

Trinidad also added a rig in April of this year to their Canadian operations where it is working in the oil sands near Fort McMurray in Alberta, drilling steam-assisted gravity drainage wells. The rig was designed in-house and built using a new moving system that allows the whole rig to move as a unit, Mr Whitmarsh said. In the past, rigs would get so far before trucks needed to be brought in to move the associated buildings, he said. Now the rig is limited only by the availability of solid, level ground on which to move the rig. “We have received expressions of interest from a number of customers for similar-style rigs to be used in both oil sands and other applications, including the Bakken.”

For 2013, Mr Whitmarsh also sees sustained interest in building new equipment, although the number of inquiries is at a lower level than 12 months ago. In particular, Trinidad sees opportunities for growth onshore Mexico, where the company currently has three rigs operating. “That was off a high for us at seven rigs, so we’d like to add more rigs back in, either in the form of a newbuild, or it could be done in an upgrade,” Mr Whitmarsh said. “Overall, we believe there are still pockets in Mexico and North America that will allow Trinidad and the industry to add assets throughout 2013.”

Pioneer further expanded its vertical integration activities in 2012 and believes it is now the 13th-largest pressure-pumping company in North America. “We’ve got over 300,000 horsepower of equipment, with most of it employed in the Spraberry and Eagle Ford areas,” Steve Mamerow, VP – corporate drilling and completions for Pioneer, said. After divesting all non-US assets, Pioneer has returned to being solely a US land company. Images courtesy of Pioneer Natural Resources.

When it comes to E&P investment, Pioneer Natural Resources believes it’s best to drill what you know. The company recently sold the last of its non-US assets in order to concentrate efforts back into familiar terrain. Previously, Pioneer had drilling activity in places like South Africa, Argentina, Tunisia, Canada, Gabon, offshore Nigeria and offshore Gulf of Mexico but is now solely a US land company. “We went into deepwater and international exploration to try and grow the company because of perceived maturity in the US at the time, but since last year we have been returning to our roots,” Steve Mamerow, vice president – corporate drilling and completions for Pioneer, said.

Pioneer made the Eagle Ford, the Permian Basin, where it predominately operates in the Spraberry and Wolfcamp plays, and Alaska its focus areas for drilling in 2012. In the Eagle Ford, Pioneer is currently running 12 rigs and had up to 44 rigs working in the Permian Basin during 2012. The company has one rig in Alaska operating off of Oooguruk Island and earlier this year during the winter drilling season employed a second rig to target additional formations.

“One well we drilled turned out to be a nice discovery in a shallower horizontal well, so we we’re going to be doing additional appraisal work on that prospect this winter,” Mr Mamerow said. Both rigs were contracted from Nabors. Rig 19AC has been under contract for three years, which Pioneer recently extended for an additional two years plus two optional years. The second rig, 27E, is contracted to drill for 120 days this winter.

For 2013, Pioneer plans to retain the same focus areas as it continues to emphasize oil assets. “Where we are drilling now is where we are likely to spend the bulk of our capital in 2013 and beyond,” he said. “We expect to focus most of our capital spending in 2013 in the Permian Basin and the Eagle Ford, where we are able to deliver superior returns.”

As much of the industry has, healthy oil prices relative to weaker natural gas pricing has driven Pioneer to place a majority of its operations in the liquids-rich areas of the US for 2012. “Our objective is to spend within our cash flow,” Mr Mamerow said. “With current oil prices, our mix of liquids to gas has been a strong impetus for us to continue to focus our efforts on places where there are a lot of liquids.”

Fueled by strong returns and the desire to enhance the execution of its drilling program, Pioneer further expanded its vertical integration activities in 2012.

“We’re now basically the 13th-largest pressure-pumping company in North America. We’ve got over 300,000 horsepower of equipment, with most of it employed in the Spraberry and Eagle Ford areas,” Mr Mamerow said. The company also has 15 drilling rigs in the Permian Basin and other service equipment, such as pulling units, frac tanks, hot oilers and water trucks.

A Newfield-operated rig works in the Eagle Ford. Liquids-rich plays like the Eagle Ford continue to attract operator budgets. Newfield, for example, has not drilled a gas well in more than a year. Image courtesy of Newfield Exploration.

As horizontal drilling expands, operators are pushing lateral lengths out longer and longer with innovations in casing design,    built-for-purpose rigs and higher ROPs. Newfield Exploration, for example, is averaging 11,000-ft laterals in North Dakota’s Williston Basin and drilling its first 10,000-ft lateral  in the Eagle Ford. “That’s not just a Newfield success story; that’s an industry success story,” Mr Campbell said. “With the success of these extended laterals, you will continue to see the lateral length get pushed longer and longer. … Our industry is able to drill the same amount of hole each year with less rigs.”

For example, in 2010, Newfield averaged 45 days from spud-to-rig release in the Williston Basin. They improved that number to 35 days in 2011, but today are “routinely getting wells down in 21 days,” Mr Campbell said. “We’re able to drill more hole per rig with higher ROPs from the same rig fleet than we could a year or two ago.”

Falling in line with the industrywide move to liquids-rich plays, Newfield has not drilled a gas well in more than a year, Mr Campbell added. “We have completely stopped investing in dry gas plays. … You’d have to see a dramatic increase in gas price, as well as a dramatic drop in oil price, to make gas investments competitive again.”

Since August 2004, the company has invested heavily in Utah’s Uinta Basin, where they are running seven rigs with an estimated activity this year of approximately 300 wells. Newfield has referenced at least 6,000 potential drilling locations in the Uinta Basin over a decade-long period of activity. “The Uinta Basin  has the deepest inventory of wells to drill over the next decade,” Mr Campbell said. “We allocated $550 million of our 2012 budget into Utah. It’s our largest oil asset in terms of reserves and production.”

Besides the Uinta Basin, Newfield’s focus areas for 2012 included the Mid-Continent’s Cana Woodford play, where the company allocated $300 million to a six-rig program, and the Williston Basin, where Newfield allocated $250 million to a three-rig program. Mr Campbell looks for these to remain large focus areas into 2013.

Newfield also has operations in Malaysia and China but holds its core assets on US land, recently selling its offshore Gulf of Mexico acreage and clarifying its role as an onshore US producer. “We’re producing a record 31,000 to 32,000 bbl/day in Malaysia, but I would not look for us to add additional areas in the international arena. Our plate is pretty full today with the existing inventory we have in the US,” Mr Campbell said.

On the regulatory side, Mr Campbell notes that challenges remain on the state and federal levels. It can take Newfield upwards of nine months to get a permit to drill a well in Utah, where they operate on federally owned land, he said. “From an efficiency standpoint, if you start and stop a drilling program, you lose efficiencies with your crews and your rigs, and that’s critical in our operations.

“There needs to be lots of preplanning and an open dialogue with those federal agencies to ensure that they understand our needs going forward and we also understand their constraints in issuing permits so we can balance that out,” he said.

Looking back on 2012, Mr Campbell stressed the improvements industry has made in reversing a decades-long decline in oil in the US. “The Williston and the Eagle Ford are two plays that are really driving that reversal of a 30-year decline in the US,” he said. “And both of those basins still have significant growth in 2013 based on the activity and inventory of uncompleted wells today.”

More importantly, the reversal has stimulated the US economy. “For the first time, we’ve made a meaningful impact in the amount of oil that’s imported into the US everyday,” he said. “Nine percent of the jobs created over the last year were created in energy, so our energy business is making an impact on the broader economy by exploiting resources in the US today. We’re removing the roadblocks to growth.”

2012 industry snapshot by the numbers

• Helmerich & Payne is most active in the Eagle Ford, where it has approximately 90 rigs employed. H&P also has 17 newbuilds under way.
• Unit Drilling upgraded and refurbished 10 rigs this year. Of Unit’s fleet, 1,000- to 1,700-hp rigs have an 85% utilization rate.
• Approximately 85% to 90% of Trinidad’s land rigs are drilling for oil or liquids-rich natural gas. 60% of the fleet is on long-term contracts.
• Pioneer is the 13th-largest pressure-pumping company in North America, with more than 300,000 horsepower of fracturing equipment.
• Newfield is averaging 11,000-ft laterals in the Williston Basin and drilling its first 10,000-ft lateral in the Eagle Ford. The company has also reduced its average spud-to-rig release in the Williston Basin from 45 days in 2010 to 21 days in 2012.