Technology is our industry’s defibrillator. Without it, we would have shared the same calamitous demise that befell blacksmiths and buggy makers. Unable to pursue any but the lowest-hanging fruit, we’d end up beating our rigs into plowshares.

Instead, thanks to our determination to drill the undrillable, we develop prospects in miles-deep water. We flipped conventional wisdom on its head and transformed the USA from a long-standing addiction to imported oil to a nation on the cusp of energy independence.

But technology demands competence in a number of interesting ways. First, the newfangled tools and rigs bursting on the stage of well development demand trained, sophisticated workers (apologies to Bubba and Boudreaux).

Second, the prospects, onshore and off, that technology has opened demand vast new rig fleets, so far largely unpeopled. Staff must be brought in and brought up to speed – pronto.

The means to ratchet up training processes resonates in all sectors of our industry. Here, our business needs align with regulatory and HSE requirements.

IADC is in the thick of the action. In late February, we posted an hour-long webinar on competency. (The webinar will remain online until the end of May.)

Sponsored by Lloyd’s Register and titled “What is Competence and how can it help your organization?”, the event featured three experts – Malcolm Duncan, Lloyd’s Register competency manager; John Tustin, Petrofac operations director of competence solutions; and Dr Brenda Kelly, IADC senior director of program development.

“Competence is a very large and complex topic,” remarked moderator Mark Denkowski, IADC vice president-accreditation and credentialing.

The thrust of the event was to define competence and the “language of competency”; outline details of employee assessment; highlight designing and implementing a competence program; and discuss helpful tools offered by IADC.

Like most complex concepts, one can endlessly define and refine the idea. Mr Tustin, however, presented an elegant and comprehensive definition: the ability to consistently perform a given task to a pre-determined standard.

Being competent is a blend of experience, skills, knowledge and understanding, and attitude, he said.

Experience, for instance, is a key ingredient. But that is not necessarily equivalent to tenure.

“I have been in this profession for 30 years,” Mr Tustin said, “but I could be less competent than Malcolm (Duncan), who has been in the profession for five years. It’s not about length of time.”

Typically, competency programs are framed around HSSE, quality, drilling operations, marine operations, maintenance, and specifics on assets or equipment.

Competency assessment is a step-wise procedure, explained Mr Duncan. Begin by planning and ensure the candidate is aware of the pending assessment. He or she must be informed regarding how his or her knowledge and skills will be judged. Assessment is not intended to be a “gotcha” effort. To the contrary, one of the major goals is building the employee’s self-confidence and identifying opportunities for coaching and training.

Next, conduct the assessment, following methodologies available from standards promulgated by ISO, API, OHSAS, and SEMS. Mr Duncan particularly recommends ISO 10667.

Then, interpret the results to weigh the individual’s competency. Last, provide feedback and evaluate the assessment.

Building your system

As in so many corporate pursuits, top-down commitment, from the boardroom to the rig floor, is critical in implementing a competence system. “It’s an essential beginning point of developing a competence program,” said Dr Kelly.

Other vital components are policies expressing commitment to a competence program; identifying responsibilities of people with key roles in the program; resources, including staff; administration processes; and quality assurance.

IADC offers a pile of resources to assist, such as our Competency Assurance Accreditation Program. IADC ensures that all components are in place and conducts a site visit.

Further, IADC is developing competency benchmarks for all rig positions. These KSAs are discussed in detail on p138.

Thanks to technology and smart competency programs, we can anticipate a sustainable future and well-trained personnel. Blacksmiths, eat your heart out.

Click here to register for IADC’s Competency webinar.

Click here to check out IADC’s competency tools.

Halliburton, Apache Corp and Caterpillar have developed dual-fuel technology to safely and efficiently power the pumping equipment used for fracturing treatments with a mixture of natural gas and diesel. With 12 pumps (24,000 hp), it is one of the largest dual-fuel projects in the industry.

G. Steven Farris, chairman and CEO of Apache and chairman of America’s Natural Gas Alliance (ANGA), encouraged Apache and the industry to increase the use of natural gas as a fuel for engines. In response, Halliburton developed a technical solution for converting the pumping equipment used at a typical large-scale fracturing spread to a dual-fuel system that includes natural gas.

Halliburton and Caterpillar teamed up to convert new Q-10 pumps to dual fuel with a technology that would accommodate high-quality liquefied or compressed natural gas. Caterpillar adapted its proprietary Dynamic Gas Blending engine technology to power Halliburton’s pumps.

Separately, Halliburton was selected by Statoil to provide multilateral technology (MLT) for two mature fields offshore Norway. The three-year frame agreement includes two optional periods of two years each and has an estimated value of more than $200 million.

The FlexRite Multibranch Inflow Control junction and the FlexRite Intelligent Completion Interface junction, of which Statoil has installed approximately 150, will form the basis of this frame agreement.  Together, these sealed junction MLT systems enable flow control capability of all laterals in multiple legged MLT wells.

ONGC sets drilling record offshore India

ONGC has set the record for drilling a well in the deepest water by an offshore drilling rig with Transocean’s ultra-deepwater drillship Dhirubhai Deepwater KG1. The rig spudded well NA7-1 in exploratory block KG-DWN-2004/1 on the east coast of India in a water depth of 3,165 meters (10,385 ft) on 23 January.

The rig then lowered and latched a subsea BOP and riser on the wellhead on 9 February to drill to TD of 5,625 meters (18,455 ft). The rig has surpassed Transocean’s prior record of 3,107 meters (10,194 ft) of water depth, set in 2011 by Dhirubhai Deepwater KG2 working for Reliance Industries on the east coast of India.

Newpark reached a production milestone with its 250,000th DURA-BASE Advanced-Composite Mat, which can withstand bearing loads in excess of 600 lb/sq in.

Milestone reached in production of protective mats

Newpark Mats and Integrated Services recently reached a production milestone with the 250,000th DURA-BASE Advanced-Composite Mat. The mats are produced from a non-slip advanced-composite formulation that withstands bearing loads in excess of 600 lb/sq in.

The production milestone also marked the preservation of over 1 million trees (or approximately 1.25 million wooden mats), along with savings in transportation costs and emissions.

The mats provide ground stabilization that minimizes the need for aggregate or gravel and enhances worker safety while preventing soil disturbance and road dust. They are designed as a single piece, with no individual parts requiring bolts or fasteners to hold them in place. The one-piece system prevents spills from being absorbed into the mats and aids in preventing spills from contaminating ground soil.

Maersk Drilling, BP to develop HPHT drilling technology for Project 20K

Maersk Drilling and BP have signed an agreement to develop conceptual engineering designs for a breed of advanced offshore drilling rigs, critical to unlocking the next frontier of deepwater resources.

BP and Maersk Drilling will collaborate on rigs that can operate in high-pressure and high-temperature reservoirs up to 20,000 psi and 350°F. The agreement is part of BP’s Project 20K, a multi-year initiative to develop next-generation systems and tools for deepwater exploration and production that are beyond the reach of today’s technology.

GE to provide HPHT technologies offshore India

Marking its entry into India’s high-pressure, high-temperature (HPHT) drilling sector, GE’s pressure control business has received contracts to supply technology for a new well to be drilled in Cairn India’s Ravva block off the east coast of India.

Separately, GE recently received a contract to supply four complete, variable frequency drive, high-speed electric motor and centrifugal compressor packages for Total E&P Norge’s new offshore production platform on the Martin Linge oil and gas field. The area is located 150 km off the coast of Norway in the North Sea, and production is scheduled to start in 2016.

Archer will carry out a plugging and abandonment contract with Statoil using the Archer Topaz modular rig in the Norwegian North Sea beginning in 2014. The rig has been designed and will be built in collaboration with Max Streicher.

Statoil to use modular Archer rig to plug, abandon Heimdal gas wells

Statoil will use the new Archer Topaz modular rig for the permanent plugging and abandonment of 12 gas wells on the Heimdal field in the Norwegian North Sea. The rig, which will be built with Max Streicher GMBH in line with current NORSOK regulations, will be operated by Statoil with partners TOTAL, Centrica and Petoro.

Carrying out plugging and abandonment operations on a modular rig is a first for Archer and the industry, the company believes.

The total contract value, including the startup, operating and decommissioning phases, is estimated at US $115 million. Operations are expected to commence in the second half of 2014, and the contract duration is 34 months, with four option periods of three months each.

“The award of this contract demonstrates the attractiveness of our modular rig concept, which combines flexibility, efficiency, short rig-up and rig-down time, making it a unique proposition for our customers both for plug and abandonment services and production drilling from fixed offshore platforms,” Kjetil Bjørnson, president and general manager of North Sea region, Archer, said.

The new rig will follow the design of Archer’s first modular rig, the Archer Emerald, which has been operating for Shell Todd in New Zealand on a production drilling contract since 2012.

Baker Hughes’ X-Treme Clean XP casing scraper was used to remove mud or cement sheath from the interior walls of casing in a Gulf of Mexico well.

Cleanup system mills 207 ft of cement,  removes 500 lbs of debris in deviated well

An operator in the Gulf of Mexico had a highly deviated (78°) and deep (30,200 ft or 9,205 meter) measurement-while-drilling (MWD)  well that needed cement milling, casing cleaning, fluid displacement and blowout preventer (BOP) cleaning. The depth and deviation of the well presented an initial challenge for sufficient cleaning. Additionally, the well had been previously displaced to completion fluid.

Baker Hughes deployed a suite of wellbore cleanup tools, mostly made up of the X-Treme Clean XP system. The customer’s workstring consisted of 4-in. and 5-in. drill pipe with high-torque XT connections.

For the milling operation, the X-Treme Clean XP system was run to a depth of 29,993 ft (9,142 meters), where the top of cement was tagged. The system then milled 207 ft (63 meters) of cement at an average of 9.4 ft/hr (2.8 meters/hr), reaching a final depth of 30,200 ft within 28 hrs. During the milling operation, three 70-bbl high-viscosity sweeps were pumped to aid debris removal.

The BOP jet sub was run to a depth of 85 ft (926 m) and made six passes through the stack. A total of 500 lbs (227 kg) of debris was removed by the filters and magnets.

Eni Norge to develop first Barents Sea oilfield, contracts for pre-laid mooring spreads

Eni Norge has contracted IOS InterMoor to provide two complete mooring spreads for development drilling in the Goliat oilfield in the Barents Sea, offshore Norway. “Goliat field is the first oilfield to be developed in the Barents Sea,” David Smith, IOS InterMoor managing director, said.

Recoverable reserves for the Goliat oilfield are estimated at 174 million bbls, and production is expected to plateau at 100,000 bbl/day.

IOS InterMoor will provide two complete moorings spreads for pre-laying in the three-year contract period. This method provides enhanced safety and integrity, as well as significant cost savings, particularly in rig moves, as it eliminates the downtime a rig spends not drilling. The reservoir drainage strategy will include water and gas injection, employing a total of eight well templates with 22 wells.

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.”

Keppel FELS has delivered the UMW Naga 4 jackup to UMW Oil & Gas five days ahead of schedule in February, on budget and with a perfect safety record.

UMW Naga 4, built to Keppel’s proprietary KFELS B Class design, is able to operate in water depths of up to 400 ft with a drilling depth of 30,000 ft. It is the fourth consecutive rig that Keppel FELS has delivered ahead of schedule this year. The company is expected to deliver 20 offshore rigs in 2013, a record number for any yard worldwide.

Vision Drilling, a subsidiary of Cyprus-based Dynamic Offshore Drilling, received the first of 20 rigs, also a KFELS B Class jackup, two months ahead of time in January.

Frigstad Deepwater has awarded CIMC Raffles a contract for the delivery of two ultra-deepwater semisubmersibles.

Frigstad confirms order of 2 ultra-deepwater rigs

Subsidiaries of Frigstad Deepwater have entered into construction contracts for the delivery of two ultra-deepwater semisubmersibles from CIMC Raffles in Yantai, China, with options for four more units.

The drilling units, deemed to be seventh-generation rigs, are of the Frigstad D90 design and will be capable of operating in water depths up to 12,000 ft and drilling to a TD of 50,000 ft. The units will be outfitted with a DP3 dynamic positioning system, full dual-activity hydraulic drilling package with 1,400 ST hoisting capacity and seven-ram BOPs.

The two drilling units are scheduled for delivery at the end of Q4 2015 and Q2 2016. The total project cost is approximately US $1.3 billion, exclusive of financing costs.

Central GOM lease sale to offer 38.6 million acres

Central Gulf of Mexico Lease Sale 227 will offer 38.6 million acres offshore Louisiana, Mississippi and Alabama for oil and gas exploration and development, announced US Secretary of the Interior Ken Salazar and US Bureau of Ocean Energy Management (BOEM) director Tommy P. Beaudreau. BOEM estimates the lease sale could result in the production of 0.46 billion to 0.89 billion bbls of oil and 1.9 Tcf to 3.9 Tcf of natural gas.

The lease sale encompasses 7,299 blocks located from three miles to 230 miles offshore, in water depths ranging from 9 ft to more than 11,115 ft (3 meters to 3,400 meters).

The sale, which will be held on 20 March at the Mercedes-Benz Superdome in New Orleans, includes all unleased areas in the Central Gulf of Mexico Planning Area.

Greatdrill Chaaya delivered, to work for ONGC

Greatship Global Energy Services, a Singapore subsidiary of Greatship (India) Ltd (GIL), has taken delivery of the Greatdrill Chaaya jackup from Lamprell Energy.

Greatdrill Chaaya is an independent leg-cantilever jackup with 15,000-psi rating, designed to operate in water depths of up to 350 ft. The jackup is contracted to ONGC for five years and will operate on the west coast of India.

With the delivery of Greatdrill Chaaya, GIL and its subsidiaries currently own and operate three jackups.

Apache, Chevron to partner on Kitimat LNG project

Apache Canada has completed a transaction with Chevron Canada to build and operate the Kitimat LNG project and develop natural gas resources at the Liard and Horn River basins in British Columbia, Canada.

Each company is 50% owner of the Kitimat LNG plant, the Pacific Trail Pipelines and 644,000 gross undeveloped acres in the Horn River and Liard basins. After a brief transition period, Chevron Canada will assume operatorship of the LNG plant and the pipeline. Apache Canada increased its ownership in the LNG plant and pipeline from 40% and will operate the upstream assets. Apache’s net proceeds from the transaction were $405 million.

Liard and Horn River are two of the most prolific shale gas plays in North America, with more than 50 Tcf of resource potential on the Apache-Chevron acreage.

Eni makes oil discovery in Western Desert of Egypt

Eni recently made a new oil discovery from the NFW well, Rosa North 1X, located in the Meleiha Concession in the Western Desert of Egypt. The well encountered a total oil pay of approximately 80 meters in multiple good-quality sandstones of the Bahariya, Alam El Bueib, Khatatba and Ras Qattara reservoirs and has been successfully tested in the reservoirs flowing a 43° to 48° API oil at very good rates.

The discovery will likely lead to the drilling of at least two development wells in 2013. Production for each well is estimated at 2,000 bbls of oil/day.

Separately, Eni and Sonatrach have started gas production from the Menzel Ledjmet East field in Block 405b, approximately 1,000 km from Algiers. A plant, located in the field, allows for the treatment of rich gas for the daily production and sale of 9 million cu meters of gas, 15,000 bbls of oil and condensate, and 12,000 bbls of liquefied petroleum gas.

Chevron finds gas again in Australia’s prolific Carnarvon Basin

Chevron’s Australian subsidiary has made the 20th discovery off the Western Australian coast since mid-2009 following further drilling success in the Exmouth Plateau area, located in the prolific Carnarvon Basin.

The Kentish Knock South-1 exploration discovery well encountered approximately 246 ft (75 meters) of net gas pay in the upper Mungaroo Sands. The well is located in the WA-365-P permit area approximately 173 miles (280 km) north of Exmouth off the Western Australian coast.

The well was drilled in 3,832 ft (1,168 meters) of water to a total depth of 10,056 ft (3,065 meters).

“The Asia Pacific region is key to Chevron’s growth strategy, and our strong Australia natural gas portfolio continues to be bolstered by our strategic approach to finding and developing resources that will help meet the growing energy needs in the region,” said George Kirkland, Chevron vice chairman.

Chevron Australia is the operator of WA-365-P with 50% interest while Shell Development (Australia) holds the other 50%.

Vantage Drilling’s Tungsten Explorer drillship has received a conditional Letter of Award for work offshore West Africa, to commence in mid-2014

Vantage receives Letter of Award for drillship

Vantage Drilling has received a conditional Letter of Award for its newbuild drillship Tungsten Explorer to work in West Africa. The award is for a period of up to four years, commencing in mid-2014. The contract has a minimum duration of two years, and the customer has four six-month options to extend the contract.

The letter of award is subject to customary conditions, including negotiating the final terms of the contract, which is anticipated to be completed in Q1 2013. The estimated revenue over the initial two-year firm period of the contract is approximately US $468 million, including mobilization.

“Since the Tungsten Explorer is scheduled for delivery in May 2013, we expect to obtain additional work for the unit to commence upon delivery from the shipyard. We are currently discussing drilling requirements for the second half of 2013 and early 2014 with both affiliates of the counterparty to this contract, as well as several others customers,” Paul A. Bragg, chairman and CEO of Vantage, said.

Petrobras makes oil discovery in Santos Basin pre-salt 

Petrobras has discovered oil in the Santos Basin pre-salt area, known informally as Florim, following the drilling of a sixth well since the Rights Transfer Agreement was signed.

The well, 1-BRSA-1116-RJS (1-RJS-704), is located at a water depth of 6,591 ft (2,009 meters), 128 miles (206 km) off the coast of Rio de Janeiro state, and the presence of good quality oil (29º API) has been confirmed in carbonate reservoirs of excellent quality just below the salt layer.

Drilling has reached a depth of 18,038 ft (5,498 meters) and will continue down as far as the depth specified in the Rights Transfer Agreement of around 2,013 ft (6,100 meters).

Seadrill orders two jackups for 2015 delivery

Seadrill has entered into an agreement for the construction of two high-specification jackups with Dalian Shipbuilding Industry Offshore in China. The units are scheduled for delivery in Q1 and Q2 2015, and the estimated total project price is approximately US $230 million per rig, including project management, capitalized interest, drilling and handling tools, spares and operation preparations.

The two new units will be based on the F&G JU2000E design, with water depth capacity of 400 ft and drilling depth capacity of 30,000 ft. The new jackups are of the same design as four other jackups that Seadrill has under construction at Dalian and Jurong in Singapore.

Mubadala Petroleum hires Atwood Orca newbuild

Atwood Oceanics has been awarded a drilling services contract for the Atwood Orca by Mubadala Petroleum. The Atwood Orca, currently under construction at PPL Shipyard in Singapore, will have a rated water depth of 400 ft, 1.5 million-lb hookload capacity, accommodation for 150 personnel and significant offline handling capabilities. The agreement is for a firm duration of two years.

The Atwood Orca is expected to be delivered in early May 2013, ahead of its scheduled June delivery. It will mobilize for a period of approximately 10 days to its first location offshore Thailand.

Figure 1: A 13 5/8-in. autofill float collar was part of a plug locator system used in a deepwater well in the Gulf of Mexico. The system provides a positive indication on the rig floor of the top cement plug’s exact position in the casing string before the plug bumps.

By Rebecca Caldwell and Bill Putman, Weatherford

The ongoing search for new oil and gas reserves continues to push the technical limits of well construction, as more complex wells are being drilled into increasingly remote reservoirs with higher-angle wellbores, higher pressures and temperatures and in deeper waters farther from shore. With this increased complexity comes greater risks in the form of safety, cost overruns and environmental exposure.

In light of these risks, the need for a high-quality primary cement job has become more critical. While much work has been done to improve primary cementing efficiency, it is widely recognized that the seemingly simple task of accurately locating the cementing plugs during cement displacement is a major factor in successful primary cementing. A successful bumping of the plugs provides a positive indication that the cement has been optimally placed, thereby allowing the casing to be tested and pressure-activated hangers or tools to operate, and minimizing drill-out time.

While the industry realizes the importance of proper bumping of the top cementing plug, the cement volume required to bump the plug is often approximated based on the calculated casing volume. This volume may vary significantly from the actual string volume, particularly in the long and large-diameter subsea casing intervals that are becoming more common.

For example, the normal practice of calculating displacement volume is based on the casing’s internal diameter (ID), with some allowance for variations in wall thickness within API 5CT specifications.

A problem arises in determining how much that allowance should be. Standard procedures call for calipering the casing ID on selected joints and calculating the displacement volume based on their average. This procedure is not very accurate, and often the net result is that the planned volume is reached with an over-displacement allowance set at half of the shoe track volume. At that time, pumping is stopped regardless of the plugs’ location, which can lead to a substandard cement job.

Operators using dual cementing plugs have attempted to avoid displacement errors by calculating the cement volume required to bump the bottom plug. This method has historically proved unreliable due to the freefall effect of cement in the casing string and the fact that, in many cases, rupture of the bottom plug cannot be observed or recorded.

Improper placement of the cement plug in the string may create challenges during primary cementing operations. For example, if the top plug is set higher in the string than it should be, cement displacement ends prematurely, preventing the top plug from bumping. This effect tends to extend drill-out time, as the non-bumped plug may rotate with the bit rather than being efficiently drilled out, and it leaves excess cement above the float collar, which further increases drill-out time.

On the opposite side of the spectrum, a top plug that is lower in the string than anticipated results in the plug bumping unexpectedly at a high displacement rate. This may lead to plug bypass and subsequent over-displacement of the cement. In a worst-case scenario, this could lead to a wet shoe with a contaminated cement/mud mixture in place between the formation and the casing.

Weatherford developed a plug locator system that provides a positive indication on the rig floor of the top plug’s exact position in the casing string shortly before the plug bumps. The system incorporates a specialized locator collar installed in the casing string, several joints above the float or landing collar where the top plug is designed to land.

The top cementing plug is equipped with aluminum yield segments that impinge on the locator collar. An additional 300 to 700 psi (21 to 48 bar) is required to compress the yield segments into the plug’s outer body and allow the plug to pass through the collar. This produces a displacement pressure spike at surface, which indicates the precise location of the plug in the string. With this information, the operator can accurately displace the cement by pumping the precisely calculated volume between the locator collar and the float collar and land the plug.

This system minimizes the uncertainties in the pumped volume when using high-volume rig pumps to displace the cement. These pumps are prone to volumetric inefficiency, which when coupled with variations in liner size, sealing efficiency and stroke, can lead to a lower pumped volume than indicated by stroke counters. It also reduces fluid compressibility issues that may contribute to erroneous fluid volume measurements, particularly if the displacement fluid is aerated. This situation can lead to a considerable reduction of volume and a consequent error in the measurement of the amount of fluid being pumped into the well once it is placed under pressure.

By enabling controlled bumping of the plug, the system ultimately mitigates the risk of cement over or under displacement, thus ensuring optimal cement placement and preventing a wet shoe or excessive cement drill-out. Further, because both the locator collar and plug are fully PDC drillable, drill-out time is minimized.

Figure 2: Pump-pressure charts of the Gulf of Mexico field trial show when the top plug passed the locator system, which gave the operator guidance on when to expect the top plug bumping.

Deepwater deployment 

The new locator system was deployed while drilling a deepwater well in the Gulf of Mexico in 6,606 ft (2,014 meters) of water. The operator ran an intermediate 14 X 13 ^5/8-in. casing string in a 17-in. hole to a total measured depth (MD) of 24,892 ft (7,587 meters).

The string, which was run on drill pipe, consisted of:

• A 6 ^5/8-in., 39-lb/ft  API full-hole drill pipe landing string;

• A 9 ¼-in. outside diameter (OD) multiple-opening diverter tool to divert fluid from the casing ID to the drill pipe annulus above the casing string and alleviate excess surge pressures;

• A 14-ft X 13 ^5/8-in. casing hanger equipped with subsurface release, non-rotating cementing plugs, with the top plug dressed with aluminum yield segments;

• Two joints of 14-in., 114-lb/ft casing;

• 13 ^5/8-in., 88.2-lb/ft casing to a plug locator collar set at 24,220-ft (7,382-meter) MD;

• 500 ft of 13 ^5/8-in., 88.2-lb/ft casing;

• A 13 ^5/8-in. autofill float collar with non-rotating profile set at 24,72-ft (7,535-meter) MD (Figure 1);

• A shoe track consisting of five joints of 13 ^5/8-in., 88.2-lb/ft casing; and

• A 13 ^5/8-in. guide shoe set at 24,892-ft (7,587-meter) MD.

Prior to the cement job, 20 casing joints were randomly selected and calipered to provide a composite average ID estimate of 12.4493-in. Based on this estimate, the operator calculated the total volume required to displace cement in all sections of the string. The volume of the drill pipe was 120 bbl, the casing to the locator collar was 2,637 bbl, and between the locator collar and float collar was 75 bbl, for a total displacement volume of 2,831 bbl.

The cement job then commenced by pressure-testing the surface lines to 5,000 psi (345 bar), followed by pumping a 150-bbl spacer of 13.7-ppg mud into the well at 10 bbl/min and 820 psi (57 bar). The bottom plug dart was then dropped, and pumping of  16.4-ppg cement  commenced. After pumping 125 bbl of cement, the dart latched into the bottom plug, and it sheared out at 1,750 psi (121 bar).

After additional pumping until a total volume of 233 bbl of cement had been displaced, the top plug dart was dropped, and a further 6 bbl of cement was pumped. The rig pumps were then used to continue displacement, with volumes measured by a stroke counter. The pumping fluid was switched to 13.2-ppg mud, and after 120 bbl had been pumped, the top dart landed and the top plug sheared out at 2,700 psi (186 bar).

Pumping continued at a rate of 10 bbl/min until the bottom plug landed and sheared out after 27,400 strokes of the pump, which was 950 strokes, or 93 bbl, later than initially calculated. The pump rate was slowed to 5 bbl/min, and when the top plug passed the locator collar, a pressure spike of 500 psi (34 bar) was observed at surface. A further 77 bbl was pumped at 5 bbl/min until the top plug landed and the pressure increased to 1,150 psi (79 bar), indicating a completion of the cement displacement. The total number of strokes was 29,740, which corresponded to a total of 2,918 bbl of displacement vs the 2,831 bbl that was calculated. The entire cement job, which is represented graphically in Figure 2, was carried out without surface returns.

Without the plug locator system present, cement displacement would have stopped some 93 bbl before the top plug landed, which would have resulted in an additional 620 ft (189 meters) of cement having to be drilled out to reach the float collar. This job illustrated the problems associated with large-volume subsea cementing jobs. Plug landing occurred at a displacement volume that was 93 bbl more than calculated due to the combination of ID deviations, pump inefficiency and fluid-compressibility inaccuracies.

The new locator system addressed these volume measurement discrepancies with a high degree of accuracy. The critical volume measurement of 77 bbl between the locator collar and float collar matched closely with the calculated estimate of 75 bbl.

This field trial demonstrated the contribution that a plug locator system can make to improve the quality and economics of primary cement jobs by increasing the reliability of top plug bumping. The company continues to make design upgrades to the system, such as the installation of a collet around the plug, which allows more than one collar locator to be placed in the casing string and provides the ability to verify plug location at different points in the casing.

This technology has proven valuable to both the quality and economics of cement jobs, not only in the Gulf of Mexico but also in other deepwater regions where risk mitigation and cementing efficiency are equally as important.

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.”

The Brazilian petroleum industry has entered a new era of success exploiting shallow-water oil reserves in the Campos Basin, utilizing methods enhanced by advanced software and buttressed by a likely world-first application of neural networking to mitigate drilling complications.

Figure 1: One challenge of a pilot well offshore Brazil was to understand the multi-mineral composition of the rock and identify intervals with the largest production potential. The boxed areas of this composite plot for the well show the top two potential target layers. The orange area is a layer of predominant calcite lithology and meso-pores texture. The green area was dolomitized with the predominant texture consisting of macro-pores.

The combination of technological innovation and groundbreaking methodology has enabled the industry to evaluate complex carbonates and achieve higher-than-expected net pays in the Quissamã Member of the Macaé Formation.

Following a pilot well, the first completed horizontal well resulted in an estimated maximum achievable flow rate of 40,000 bbl/day of oil without movable water. Net pay was 80%, exceeding the initial goal of 65%.

Operator OGX Petróleo e Gas faced the task of identifying target zones in an Albian (Upper Cretaceous) carbonate reservoir. The complex reservoir section consists of a lower half dolomitized with metric thickness shoaling upward cycles from matrix to grain-supported rocks. The upper segment includes mostly beds of grain-supported limestone with secondary siliciclastic richer beds.

The average porosity is 15%, occasionally reaching 25%. Cores and electric/ultrasonic image logs in the pilot well identified closed and oil-bearing open fractures.

Figure 2 shows the neural network results for free fluid volume. In the circled portion of the graph, the blue curve is the output of the Techlog K.mod module. It is superimposed over the black curve, which is the input.

The S-shape pilot well crossed stratigraphically the whole reservoir, with the team from OGX Petróleo e Gas and Schlumberger using data to identify a target zone for a 1,000-meter lateral in the horizontal well.

The team utilized Schlumberger’s logging-while-drilling (LWD) and wireline technologies to compare the two, characterize log reservoir signatures before and after mud filtrate invasion, and support real-time horizontal well petrophysics interpretation for geosteering decisions in the subsequent well.

The bottomhole assembly (BHA) in the pilot well consisted of a PDC bit, point-the-bit rotary steerable tool, LWD laterolog imager, LWD nuclear magnetic resonance (NMR) tool, LWD multifunction formation evaluation tool and measurement-while-drilling (MWD) tool to transmit real-time data. An optimized physical transmission rate was selected to obtain real-time data similar to memory data.

The challenge was to understand the multi-mineral composition of the rock and identify intervals with the largest production potential.

Lithology was defined in the pilot well using capture spectroscopy by a pulsed neutron LWD source, coupled with high-resolution NaI detectors. NMR tools were chosen to analyze the rock texture and determine the connectivity of the pore structure.

The deployment of the LWD tool was a first for the operator, who used synthetic oil-base mud (SOBM) in the pilot well.

In Figure 1, the two boxed sections show the top two potential target layers. The area in the orange box is a layer of predominant calcite lithology and meso-pores texture. The zone indicated by the green rectangle was dolomitized with the predominant texture consisting of macro-pores.

Differences in textures indicate effective permeability in the second layer up to 10 times larger than the top interval of similar porosity, leading to a decision to bypass the top layer in the horizontal section.

The pilot well also provided an opportunity to validate the new NMR measurement available in Schlumberger’s proVISION Plus magnetic resonance while drilling tool.

The tool, consisting of a 6 ¾-in. collar centered in the borehole using two spiral stabilizers, performed a focused measurement over a resonating ring zone 14 in. in diameter and roughly a ½-in. thick.

The magnetic field has a low gradient, minimizing diffusion effect. The cylindrical symmetry allows the collar to rotate freely without affecting the measurement.

In the water zone, the LWD NMR and combinable magnetic resonance (CMR) data were directly comparable and equivalent. The bound fluid volume (BFV) measured by CMR overlaid irreducible water measured by the magnetic resonance while drilling tool, demonstrating that, under comparable conditions, the two measurements are closely interchangeable and will lead to consistent results.

After proving data overlay in the water zone, the same measurement was observed in the oil zone.

With data in hand, the operator targeted the layer with partial oil re-invasion, good dolomitization and an overall combination of the best petrophysical properties.

Figure 3: To reconstruct nuclear magnetic resonance-equivalent data using a neural network approach in real time, a principal component analysis was performed. The position of the dots illustrates how the variables correlate.

Two kilometers separated the discovery well and the landing of the horizontal well. To reach the aggressive net pay goal, the team made extensive use of real-time petrophysics, integrating both the LWD and wireline data and updating models to support geosteering decisions.

Schlumberger’s RTGS real-time geosteering software was used to build a geological model using the seismic data for its structure and the pilot petrophysical data to propagate properties along the trajectory.

A petrophysics analysis was run in parallel to guarantee the best well placement. NMR was used for net pay count and pore-typing; spectroscopy for elemental analysis, leading to facies recognition and matrix density determination; and images to compute dips and adjust borehole inclination.

The operator opted for a low damaging water-base mud (WBM) instead of SOBM. Textural analysis was performed using the same method and achieved a response similar to the pilot hole.

Identified were zones with calcite lithology close to the top, a combination of calcite and dolomite composing the second reservoir for the sweet spot, and bottom intervals containing a highly dolomitized zone.

The pilot well showed that some intervals with high gamma ray could correspond to zones with high resistivity, atypical of shales. Capture spectroscopy indicated a high quartz content but not clay.

Consequently, these zones could well contain movable oil and contribute to net pay. The true stratigraphic thickness (TST) of the top carbonate reservoir was estimated at around 25 meters, dipping 22° from horizontal in the direction opposite to the well trajectory at reservoir entry.

In the 12 ¼-in. section, the shoe was successfully set at a level corresponding to the second layer from top.

The initial challenge in the 8 ½-in. horizontal section was to build the angle with the maximum allowable dogleg severity (DLS), based on completion limits, to track the upper section of the reservoir, which was dipping against the trajectory for the initial 300 meters.

Resistivity images allowed computing relative dips in real time and monitoring the progress of reservoir structure folding. Well deviation increased from 82° at landing to 89° at 300 meters from it.

Spectroscopy and NMR provided formation evaluation in real time, in addition to density, neutron porosity and 2Mhz propagation resistivity. The best reservoir intervals were identified and net pay accrued using NMR-derived free fluid volume (FFV).

The meso- and macro-pore intervals were easily recognizable. Spectroscopy confirmed the rock dolomitization characteristic of the optimum layer. All water was irreducible. Permeability based on NMR texture was computed using a pore-partitioning for permeability analysis algorithm that can predict the enhanced permeabilities observed over macro-pore intervals.

Figure 4: Meso- and macro-pore intervals are recognizable in the initial reservoir interval in the horizontal section, and all water was irreducible. Spectroscopy confirmed the rock dolomitization characteristic of the optimum layer.

After the first 300 meters, the trajectory was dropped to avoid exiting from the reservoir roof.

A tool hardware failure at this point resulted in no NMR data being available for steering or evaluation over the later part of the well.

Instead of a costly trip to replace the faulty tool, the team used all previous data to reconstruct NMR-equivalent data using a neural network approach in real time, which the companies involved believe was a world-first application.

Data from six spectroscopy mineral fractions were selected to characterize dependent lithological formation properties. Bottom-quadrant densities (ROBB) and thermal neutron porosity (TNPH) were selected because formation density and porosity are related to FFV. Sigma was added because invasion affects shallow measurements.

Estimating logs using neural networks requires the definition of the structure of the network, followed by training on the data set with check to verify convergence of the training process and finally application of the trained network to independent data sets, all while checking for consistency.

To select an interval where all the logs had reliable values, the rat hole section was excluded. The first target variable was FFV. The same variable was checked against known values and not chosen for training. The match (Figure 2) was very encouraging.

The synthetic FFV obtained through the neural network method, implemented using the K.mod module available in the Schlumberger Techlog wellbore software platform, showed only minor discrepancies from spectroscopy, with a lower vertical resolution than NMR due to depth averaging.

The K.mod module within the Techlog software platform has consistently demonstrated its capacity to extract essential information from log data to predict non-recorded parameters and reconstruct missing or poor-quality measurements to compensate for bad hole conditions, environmental effects, acquisition problems and other factors. The software also allows for controlling of scale shift management from core to reservoir scale and comparing well log and core data to reduce the need for coring and plug analysis.

Figure 5: The horizontal well had zones with calcite lithology close to the top, a combination of calcite and dolomite composing the second reservoir for the sweet spot, and bottom intervals containing a highly dolomitized zone.

Principal component analysis was performed to determine if input channels were optimal. Figure 3 shows the results. The position of the dots illustrates how the different variables correlate to one another.

The evidence that most of the dots are occupying different spots in the correlation ellipsoid indicates that the variables are independent and their contribution significant.

Eventually, in this case only, the pyrite weight fraction is closely related to clay content and not completely independent from it. Results, however, were practically unchanged removing this channel, so this combination of inputs was used in the final evaluation.

The same network structure and principles were also used to estimate NMR permeability. Figure 4 already displayed the synthetic permeability on top of the one directly derived from NMR.

Over this interval, estimated permeability using neural network and spectroscopy matches NMR data, with the exception of the macro-pore intervals, where the achievable dynamic range is slightly reduced. Figure 5 shows a deeper section of the horizontal well.

Below the last available NMR data permeability, FFV and BFV were estimated using the K.mod method. The results show reliable and conservative permeabilities and confirmed the absence of movable water. With these data, it was possible to continue drilling with confidence in formation evaluation.

After drilling, the contingency run with a new NMR LWD tool was canceled because the operator was confident that collected data was sufficient for a proper evaluation.

This article is based on SPE OTC-22738-PP, presented at the SPE Latin American and Caribbean Petroleum Engineering Conference, Mexico City, Mexico, 16–18 April 2012.

Bob Newhouse, member of the KSA steering committee and vice president – learning & development for Noble Drilling, speaks with Drilling Contractor associate editor Katherine Scott about the project.

By Katherine Scott, associate editor

The Drilling Onshore workgroup for IADC’s KSA project met on 25 February to discuss competencies for 73 land rig positions. Clockwise from top left are: Joe Ed Bunton, Lone Star College; Linda Horr, Sidewinder Drilling; Malcolm Singh, Petrofac; Linda Head, Lone Star College; and Brooke Comeaux, IADC.

The IADC Knowledge, Skills and Abilities (KSA) project is well under way and headed toward completion later this year, with worldwide mapping of competence-based models already completed, Dr Brenda Kelly, IADC senior director of program development, said at the 2013 IADC HSE & Training Conference in Houston on 6 February. The work continues to focus on rig-based positions, Dr Kelly said, “but ultimately there is that vision on expanding to other third-party personnel who will be coming to the rig. That’s on the horizon.”

The goal of the project is to add to IADC’s original KSA templates created in 2000 and provide a foundation upon which the industry can demonstrate personnel qualifications. Currently, IADC is conducting member surveys on in-house competency programs and requesting voluntary sharing of their personnel competency information to contribute to a database pool, Dr Kelly explained. The project was announced in June 2012, and once completed, the new guidelines will be open access.

IADC continues to gather input from its members for the KSA project, which will provide a foundation to demonstrate personnel qualifications, IADC senior director of program development Dr Brenda Kelly said at the 2013 IADC HSE&T Conference & Exhibition in Houston on 6 February.

By defining key competencies, the KSAs can also form the building blocks of future IADC accreditation and certification programs. IADC is renowned as an accreditor for drilling-industry training programs conducted by oil companies, drilling contractors, oil-field service firms and independent training institutions.

“The revamped KSAs will provide the industry with a benchmark for globally consistent drilling position requirements, as well as recommend means for effectively evaluating personnel,” remarked Stephen Colville, IADC president and CEO.

Nine review teams have been put in place to oversee quality, health, safety and environment; processes and procedures; drilling operations onshore; drilling operations offshore; marine operations; technical maintenance; facility management; subsea operations and regulatory. “All of these review teams are actively at work going through the input, the KSAs that have been contributed through us,” Dr Kelly said, adding that the facility management and regulatory teams particularly need additional members to pitch in and help. Review teams are expected to complete their work in the next two months.

Additionally, a steering team, made up of drilling contractor operations-level personnel, will act as the deciding body during the approval process for the finalized KSAs, Dr Kelly said. “This is a back-and-forth process as we work through the inputs, the review teams examining and seeking more input if needed.”

Eventually, a database will be developed to house and provide a means of generating the KSAs. Dr Kelly noted that database platform selection has just begun, and competencies will be organized by group function, units of competency, elements of competency and then a checking of each position for which of those competencies are either core or alternates. “You have options coming into the system, designating position, designating the rig type, the environment where the rig will be working, the geography that influences the regulatory input, and other rig-type topics, like equipment. You’re generating a unique set of KSAs for each type of position within your organization.”

Based on the KSA template, IADC will also provide guidance for implementing a competency program. “That would include suggestions for assessment methodologies, as well as recommendations as to accepted ranges of performance on each of the competencies,” Dr Kelly said.

There is still time to contribute to this industry milestone project. “We want this whole development process to be very transparent as it evolves and give everyone a chance to comment. We want to get to the end game with everybody on the same page,” Mark Denkowski, IADC vice president – accreditation & credentialing.

Please contact accreditation@iadc.org for more details.

Click here to view IADC’s competency webinar.

Top left: Saipem’s Scarabeo 9 rig was retrofitted with an umbilical winch, a control container and office/tool container to use the EC-Drill dual-gradient drilling system. Top right: A modified riser joint, part of the dual-gradient system, is run through the rotary table on the Scarabeo 9. Bottom right: The bottom of the pump in the C-1 well was equipped with a mud return line and riser connection. Bottom left: Preparations for the pump module are made in the rig’s moonpool.

By Katherine Scott, associate editor

IADC defines dual-gradient drilling (DGD) as a variation of managed pressure drilling that uses “two or more pressure gradients within selected sections to manage the well pressure profile.” Although it’s not exactly new technology – it was introduced as early as 1975 – after years of research and trial, DGD is now on the verge of changing the face of deepwater drilling, with a successful application on the ultra-deepwater exploration well C-1 in the Gulf of Mexico (GOM) in May to July 2012. During the project, PETRONAS and AGR successfully applied what the companies believe to be the world’s first controlled annular mud-level type DGD system in the 17 ½-in. and 12 ¼-in. sections. No losses were seen, and the hole was in good condition with no indication of fill or drag through the 47 days the system was in operation.

“People initially think DGD is complex, but nothing has really changed. Flow in still equals flow out. The only thing that changes is that the riser level is no longer at surface, but you still measure bottomhole pressure (BHP) with pressure while drilling (PWD) in exactly the same way. Once you realize that, and it’s all the same that you’re used to, people then become a lot more comfortable with this type of drilling,” Paul Ashley, exploration well delivery manager – Atlantic region for PETRONAS, said.

The above figure shows that ROP increased when the riser level was reduced in the 17 1/2-in. hole section.

When a previous drilling attempt on the same field did not reach its objective due to an inability to maintain a water-based mud system light enough to sustain circulation, the operator decided it needed a system that would allow for dynamic management of the equivalent circulating density (ECD). It was decided that conventional rotating control device management systems were not suitable because the drilling fluid was not light enough to manage the ECD via backpressure. Further, with a rotating control device, the riser top would have to be modified. “As we were in the GOM with the possibility of having to drill in the hurricane season, any modification to the top system of the riser would change the weather window the rig can operate in,” Robert Ziegler, head of deepwater drilling technology for PETRONAS, said.

Dual-gradient operations in the 17 ½-in. section started in June 2012 with a mud weight of 9.2 ppg. Riser level was reduced until it was at an ECD of 9.0 ppg, then it was further reduced to 8.9 ppg. During drilling, there were variations in flow, but the system maintained the riser level at the desired level of 8.9 ppg.

Over a six-month period, PETRONAS and AGR jointly designed the EC-Drill DGD system for drilling post-BOP sections. The system uses a subsea pump installed on a modified riser joint to manipulate the height of the drilling fluid in the riser annulus. By manipulating the fluid level in the riser, it is possible to alter the hydrostatic pressure seen by the wellbore and control the ECD while drilling. The system also makes it possible to evaluate pore pressure/fracture gradient, early kick and loss indication and reduce formation damage.

The figure above shows that ROP dropped when the riser was filled.

DGD can be applied under several scenarios, including where fractured carbonates have high potential losses and in narrow pressure windows when BHP needs to be controlled, Roar Malt, drilling advisor for AGR, said. “Also, it’s possible to use DGD in deepwater with the sole purpose of reducing the number of casing strings. In some areas, it’s necessary to use five or more casing strings to reach total depth, but using DGD with high mud weights reduces the number of casing strings. That’s a huge benefit.”

Compared with a typical backpressure-based MPD system, the EC-Drill reduces the actual height of a heavier fluid column, allowing for a significantly flatter mud pressure gradient much closer to nature. This leads to a significantly lower pressure at the weak shoe, while maintaining the required pressure to control moveable formations.

The system consists of surface and subsea equipment, such as an office and tool container; control container; winch with umbilical; hose handling platform; control and monitoring system; subsea pump module; mud return line; and modified riser joint.

“There aren’t really any other commercially available dual-gradient systems on the market. One of the enablers for this technology is for the drilling contractors to work very closely with the operators who want to use it,” Mr Ashley said.

The EC-Drill system was also used while cementing the 13 3/8-in. casing. Above, at the first arrow, the riser level was lowered 300 meters to account for the increased bottomhole pressure while displacing the cement slurry up the annulus. At the second arrow, after the cement had been displaced, mud level was kept at 300 meters for 1 ½ hrs. It was then raised back up to account for the loss of hydrostatic head.

Although the AGR crew was familiar with the main components of the EC-Drill system, the application was new and had important changes compared with the riserless mud recovery system that the company predominately used previously. Therefore, before operations commenced, a one-day course describing the system and its application was held for the entire crew, followed by a one-week internal course. During the weeklong course, participants were presented with a module that explained the basics of drilling, formation pressures and volume control and how these aspects are affected by the EC-Drill system. Then, participants received a module that described the equipment, the installation and deployment procedures. Finally, the control system was explained in detail and the course was completed with a test. Operators were set up as a normal crew in order to make the test realistic.

AGR also built an in-house, onshore wellsite information transfer specification (WITS) simulator that connected to the EC-Drill control system program and helped operators practice operational procedures. It enabled the trainer to test trainees on operating the system’s equipment in various operational scenarios, such as normal drilling ahead, tripping, kick/loss incidents, etc. “We had a one-day simulator training where we drilled the entire well, so we knew the system and how to use it in the operation,” Kjell-Rune Toftevåg, senior control system manager for AGR, said.

The C-1 well was spudded on 25 May 2012 in 2,260 meters of water from Saipem’s Scarabeo 9, a dynamically positioned sixth-generation semisubmersible. A 24-in. hole was drilled to 3,161 meters TVD before the riser and BOP were run. The EC-Drill system was then run together with the riser.

DGD operations commenced on 21 June; a 17 ½-in. and a 12 ¼-in. section were drilled. The formation in both sections was generally carbonates, with potential for severe or total losses. DGD was applied to prevent losses from occurring, and dynamic circulation pressure effects were eliminated. The DGD topside system was rigged up offline, and when running the riser, the DGD pump was launched and attached to the riser for the last 400 meters of riser running.

The plot above shows the relationship between ECD readings from PWD, riser level and flow. Note that as flow is increased, the ECD is decreased due to reduction of riser pressure.

There were variations in flow, but the EC-Drill system was capable of maintaining a riser level of 150 to 200 meters with 1,650-gal/min flow in the 17 ½-in. section, which was above expectations, and ROP was demonstrated to increase when decreasing BHP.

In a technique called managed pressure cementing, the EC-Drill system was also used while cementing the 13 ³/8-in. casing to control BHP. In deepwater drilling where there’s a narrow margin, inevitable pressure makes it difficult to cement the casing or liner in place, potentially resulting in losses, Saiful Anuar Sabri, onsite drilling engineer for PETRONAS, said. “This system lowers the pressure level such that you can circulate prior to the cement job, and when the heavy cement goes through the shoe and starts rising in the annulus, you can drop the level further to eliminate that pressure you get during cementing. It’s the difference between a good cement job and one with losses. We applied the EC-Drill during cementing, and it was very effective.”

One lesson learned was that because of the abnormally high pressure differential at the casing-running tool caused by the reduced riser level, a much higher set-down weight than normal was required to set the seal assembly. This was initially not taken into account, and first attempts therefore failed. After applying sufficient weight, the seal assembly was successfully set and tested.

The figure shows that ROP increased when riser level was reduced in the 12 1/4-in hole section.

“If there is ever a seventh generation of deepwater rigs, such a system should be standard equipment because it has benefits in any deepwater drilling scenario,” Mr Ziegler concluded. “Industry has understood that DGD is a game changer for deepwater drilling, and there have been a whole series of field trials with complex systems, but the system that we have now developed with AGR is a simple system that can also be easily retrofitted on an existing rig.”

The C-1 well was drilled using conventional methods of influx detection (Schlumberger/GeoServices Early Kick Detection System, PVT readings of the active system, and gas/salinity levels in return flow), and because the EC-Drill pump is installed below the slip joint, the return flow is not affected by vessel motion. In addition, the power consumption of the subsea pump module’s centrifugal disk pumps was monitored since it’s directly related to the volume of the mud pumped. Therefore, variations of the power consumption serve as a kick/loss detection instrument with steady-state flow-in. This kick/loss detection capability is within a single barrel, considered a major breakthrough on a floating rig.

There were zero incidents relating to influxes into the wellbore while the EC-Drill system was in use, and the mud weight was always maintained high enough to ensure that loss of the mud pumps would not lead to the wellbore becoming underbalanced.