By Linda Hsieh, assistant managing editor

Susan Cunningham is senior vice president of exploration for Noble Energy.

Susan Cunningham

DC: As someone responsible for assessing and determining potential exploration targets that require millions of dollars to drill, what is your view of risk management?

Cunningham: Risk management is what we do all the time, just by definition with exploration. My view of risk management is that it’s a disciplined process, and you can’t go by gut feeling. Gut feel is the road to perdition. A great example is what happened in the US economy – that was all about people not managing risk properly. The discipline was lost. Risk management means having a disciplined process to understand the risks, then make good decisions.

DC: You made a presentation to the Drilling Engineering Association at its annual workshop in August 2009 in which you advocated the use of intuition in exploration. How does that fit into your view of risk management?

Cunningham: Intuition isn’t gut feel. I define intuition as trained experience based on what has worked and not worked in the past. That’s helpful intuition.

Natural gas demand continues to grow in Israel, where Noble Energy announced its Tamar and Dalit discoveries in 2009. The company has a process in place to continually learn from its exploration failures in order to improve future exploration efforts.

Let me explain it this way: For athletes who are at the top of their game in various sports, what is it that makes them able to consistently perform so well? Studies have been done showing that the athletes who are at the top of their game are always looking at the results of their performance. They’re always looking back and saying, “I should have made that pass better. What did I do that was right on this one? What did I do that was wrong on this one?” They’re always evaluating their performance, doing what we call postmortems.

With trained intuition, the brain is constantly looking at and evaluating what works. From an exploration perspective, we look at every well drilled, successes and failures, and look at what worked and what didn’t so you get a better sense of the risk. When an athlete is actually in a game, they don’t have the time to do the analysis. The brain is already trained, and the emotion says this feels right to throw the ball to that person now. When I talk about intuition, it’s only the trained brain that adds value.

DC: So this is an intuition you can train your employees to have?

Cunningham: Absolutely. If you have a process so that the teams are learning from all their exploration failures, that’s the training.

DC: From that perspective, it seems like maybe failing isn’t necessarily a bad thing.

Cunningham: Human beings actually do the best learning when they fail. That’s why people tend to grow from experiencing hardships and failures. To me, if a company is successful all the time, they’re going to fail because they’re not learning. It’s not sustainable unless you have a process that helps you focus on learnings. And when you’re successful, it’s easy to get lazy.

It’s all about making sure you have a disciplined process to never get lazy. Never allow complacency.

DC: Other than risk management, what are the critical issues you spend your time dealing with?

Cunningham: Ensuring that Noble has the competitive technologies on the geoscience and exploration side and the appropriate technologies for the types of projects we have. That we have talented people and keep them trained. That we have processes to translate all the technical interpretation into numbers that are meaningful for our portfolio of investment opportunities from a value-add perspective. That we have the right processes to then decide which are the right ones to invest in.

DC: So what advances in the geosciences are you’re looking for?

Cunningham: On the seismic side, it’s always going to be the emerging technologies and advances that can help us understand imaging in complex terrains, through seismic as well as in understanding the rock properties – the rock properties of the rock and the rock properties of what’s in the pores of the rock.

Advances are also being made in terms of tectonics and the impact on rocks, like salt movement, depositional systems, as well as geochemical modeling, understanding pore pressure and understanding geochemical changes in the subsurface.

DC: What are the gaps between what you’d like to achieve and the technologies that are available to you in seismic or imaging?

Noble Energy received an award from the Colorado Oil & Gas Conservation Commission in 2009 for environmental protection and safe operations in the Project Rulison area of the Piceance Basin.

Cunningham: I always have a hard time with questions like that. What we’d all like to achieve is to have all the answers – to see everything. But that’s just not realistic.

It’s hard to predict what future technologies will be, but the ones that help the business from my perspective fall in two categories. One is the IT-type technologies, which is how we work together across the globe. Things that enable virtual collaborations between disciplines around the world, whether it’s from the rig site to the office or people located in different offices. Then it’s the technologies specific to our industry in geology, geophysics, drilling, completion and production.

I have a hard time answering because who knows where the future will lead? We’re always trying to improve our understanding of the different elements that go into an exploration decision and how we make our decisions and understanding risks. Anything that helps us understand source, presence and maturity, migration, as well as reservoir characteristics, field characteristics and trap characteristics.

DC: Where are Noble’s focus areas as far as exploration?

Cunningham: Our focus areas are the deepwater Gulf of Mexico, predominantly subsalt, as well as West Africa and the eastern Mediterranean. We also have tight gas plays onshore US in the Rockies, Midcontinent area.

DC: In the Gulf of Mexico, what are the challenges you’re dealing with in imaging the subsalt?

Cunningham: Most of the rock property work like bright spots and amplitudes work in the shallower, above-salt setting, but they don’t tend to help you out below salt. Salt disperses the energy so much from the seismic waves, making it hard to interpret. The huge resurgence in significantly sized discoveries in deepwater Gulf of Mexico is all because of imaging technology improvements.

DC: What kinds of improvements?

Cunningham: Things like wide azimuth seismic acquisition and reverse time migration technologies.

DC: As technologies improve, such as with wide azimuth as you mention, are you finding yourself having to deal with an increasingly significant amount of data?

Cunningham: Yes, dramatically. Therefore the next technology we need is being able to manage all that data. That’s all about algorithms, computing, capacity, etc. Computing capacity is increasing, which allows the technologies to acquire more data, and more data means more precision. But it’s also important how you manage it and make your decisions.

DC: You also mentioned doing work in the US shales. What are your challenges there?

Cunningham: It’s a different understanding of rock properties than for conventional plays. It also translates very quickly to completion strategy and technologies.

Tamar, Noble Energy’s largest exploration discovery in company history, is expected to begin producing in 2012. The Tamar-2 appraisal well offshore Israel was drilled in 5,530 ft of water to a total depth of 16,880 ft.

In these shale plays, you’re basically getting the hydrocarbons from the source rock, not waiting for it to migrate into a higher-permeability reservoir rock. And, really, rather than shales, I would just call it tight rock. I think we’re discovering that shale plays are really not shales – they’re just shaly sands or shaly carbonates.

DC: So we’ve been able to produce hydrocarbons from them because they’re not true shales?

Cunningham: Correct. It’s a continuum. There’s shale that’s like clay… the gumbo stuff. We’re not producing from that. What we’re producing from has just enough small grains of sand or carbonate to give it some porosity or permeability. People still call them shales because they’re predominantly shales, but there’s a continuum.

I don’t think the industry is producing from anything that’s 100% shale.

DC: Has development of tight rock resources in the US led to similar exploration opportunities in other regions around the world?

Cunningham: Sure, it’s not like these rocks exist only in the US, and it’s already starting to happen. People are lifting their heads and looking at where else in the world this might work. It is something on Noble’s radar screen as well.

DC: Overall, what do you think are the most critical challenges facing the drilling and completion industry today?

Cunningham: You’ve probably heard it ad nauseam, but it’s going to be safety, efficiency, cost and environment. When activity levels went up (in the previous boom), safety statistics got worse because so many new people were coming in and there was not enough time to train people properly. We have to keep safety number one. Then, efficiency and cost are related because if you’ve got high efficiency, the cost should go down.

Environment is also important and becoming more important everyday. We have to be really cognizant of our impact on the communities we’re working in, and that’s a big challenge. We have to really think about what we’re doing in the environments where we operate. If we don’t pay any attention to that, the situation will become more adversarial than it is.

Water is also an important challenge, especially with water being used more and more in the tight plays. It’s already becoming an issue and will become more significant as the population in the world continues to increase. We really have to work on that.

The bounty of rich hydrocarbons that lies deep beneath the ocean floor holds great promise for an industry that is continually searching for new production frontiers. But tapping that prize brings a host of challenges and obstacles, not the least of which lies in an element that can trigger a multimillion dollar failure if it is not handled properly: sand.

“Deepwater wells are like a space shot,” says Luis Rivas, completion engineer, deepwater exploration and production for Chevron North America. “You have to get it right the first time. If you start producing sand, it can cut out, just through erosion, your tree, flowlines, jumpers, chokes and other well components, and cause a well to fail. And when these wells fail, they fail big.”

Nowhere is this more evident than the Gulf of Mexico, with its high-pressure conditions, long intervals, unprecedented well depths and unconsolidated sands. Controlling sand production is a key completion challenge that Mr Rivas and Chevron have faced in the GOM’s Tahiti Field, where wells are producing at 26,000 ft and 20,000-psi bottomhole pressure.

In the Gulf of Mexico, frac packs have delivered reliable and efficient completions with little pressure drop across the completion. They also have a low skin value, risking little damage to the wellbore. Above, a frac head that connects the surface treating lines to the workstring.

“Whether to engage sand-control measures has been probably the single biggest completion design decision,” he said.

Sand control is currently considered the default solution for deepwater production wells. Making that decision requires balancing the cost of implementing sand-control measures with the overall economic viability of the well. “Completions must be cost-effective, reliable for the long term and optimize the production stream from the well,” Mr Rivas said. The process is difficult because operators don’t have a lot of history in deepwater, so not much reliable well data are available.

Several factors determine whether sand-control measures should be engaged, he explained. Characteristics of the rock are generally the first order of business and involve cutting, then testing, core samples from the well itself.

“Sometimes we’ll do hollow cylinder tests to try and mimic what is happening downhole while producing a well, and see whether the sand is going to crumble, come apart, fill the wellbore and cause a failure of the completion,” he said.

Other factors include the length of time the well will be producing, the degree of drawdown, effects of production on the formation pressure and whether the formation has strong aquifer support such that the pressure won’t decline.

“If I exceed the safe drawdown pressure (SDP) on the well, if I pull the well harder than, for example, 1,500 psi, I will probably need sand control,” Mr Rivas noted. “If I stay below 1,500 psi drawdown, or within the limits of the calculated SDP, I don’t need to install sand control. Or, if reservoir pressure drops below a certain value, which affects SDP, I need sand control at that time. I’m probably not going to pull the well apart and install sand control at that point. I’ll install sand control upfront during the initial completion, which is a much more cost-effective approach.

“To a certain degree, if the pressure in the reservoir rock goes below a critical value from producing the well, or if the aquifer support was not there or was weak and the reservoir becomes depleted, the overburden tends to crush the rock at producing intervals, and the well fails. Then we start producing sand.”

In many cases, deepwater projects present multiple layers of sand that are stacked up three or four high, Mr Rivas continued. “We sand-control each layer, but if one fails, especially one of the lower ones, the cost of remediating that whole completion is even higher because now we have to pull out completions that were in good shape to go down and get the offending one that has come apart, and reinstall it. That is costly and high-risk, and we may lose the wellbore as we are trying to clean everything out. And the fix is generally never as good as the initial completion.”

Halliburton’s Stim Star III frac boat was used to pump frac pack treatments on Chevron’s wells in the GOM. The DP vessel can maintain its position independent of the rig via sonar and satellite. The coflex hoses on the back of the boat unreel from the vessel and are attached to the rig to pump the frac treatment from the boat down the well.

Further complicating the sand-control dilemma is the notion that sand can be managed rather than controlled, an idea that appeals to some in the industry who believe that managing versus controlling sand can reduce the completion’s complexity and cost.

“Managing sand means we won’t install sand-control measures, and we will operate the well by reducing the drawdown and the choke,” Mr Rivas explained. “We’ll have sand detectors in the tree, at the platform, in the flowline, and we will dial that well’s operating condition in to where we will limit the amount of sand that well produces to a pound per barrel or a pound per five barrels, or whatever the surface facilities can handle.”

That approach has been used in the North Sea, but formations there behave differently from those in the GOM. “The North Sea wells in which sand management has been successful can be operated in such a manner that when they start producing too much sand, the operators can choke them back and reduce the amount of sand produced and still have a competent well that is producing oil, water, gas and some sand,” Mr Rivas explained.

“But in the GOM, if we exceed a certain safe drawdown, the sand doesn’t come apart like snowfall in reverse, lifting off one grain at a time. It tends to fail catastrophically to when the well fails, everything – the tubing, the flowlines, even the separators – are full of sand.

“The problem in the Gulf of Mexico is that no one has really been able to accurately predict how we can manage sand production,” he continued. “We don’t know how to determine how much sand will be produced and the particle size distribution. We are pretty good, as an industry, in forecasting the reservoir pressures and drawdown at which the sand will come apart, but we don’t know the other critical parameters, like the rate of sand production and whether the sand will come apart in a nice controlled manner or all at once.

“All we can do is guess how much sand will be produced if we go below a certain pressure in the well, and that’s the critical question. And in the Gulf of Mexico, nobody wants to be the first to jump off a cliff with a deepwater well that costs $150 million, and investigate sand management by opening up the choke until a well fails.”

The big downside to sand management is that it can restrict the well production rate and thus jeopardize profitability, Mr Rivas said.

“If we’re talking about curtailing production to manage sand, we also have to look at the revenue side of the equation to make that decision,” he said. “If we have 40 wells producing and we are at the limit of our facility, then we can maybe choke back a few wells and defer some production. But if we need the maximum production from each well, which requires the highest drawdown we can safely put on a well, we don’t want to curtail that production over time to save a few dollars upfront while installing the completion.”

Sand-control options range from frac packs to high-rate water or gravel packs and screens. In the GOM, frac packs are generally considered to be the best sand-control completion option. “Frac packs deliver a very reliable and efficient completion in the sense that there is very little pressure drop across the completion, and they have a low skin value, risking little damage to the wellbore,” Mr Rivas said.

“Frac packs generally deliver a skin in the zero to three range, which is very robust. In addition, the mean time to failure for a frac pack is much longer than it is for a high-rate water pack or gravel pack or for stand-alone screens.”

The downside of frac packs is that they are more expensive. “But that gets back to the issue of total cost of ownership,” he said. Because gravel packs cannot be subjected to the same amount of drawdown as safely as frac packs can, the completion won’t be as efficient. “A gravel pack puts sand or proppant in the perforation tunnels, which only extend six to eight inches at most,” Mr Rivas explained. “A frac pack can extend up to 120 feet out, giving us bigger proppant in a fracture that is more conductive, which allows us to draw the well down more and gain a longer mean time to failure and higher reliability in bringing production into the wellbore.”

Frac packs may be more expensive, but their mean time to failure is longer than high-rate water packs or gravel packs or for stand-alone screens. Above, looking up at the frac head on the Cajun Express, which Chevron used to conduct a well test in the GOM.

Gravel packs can be viable in shallow waters or mature areas where reserves are smaller and production rates lower, and don’t justify the cost of bringing in expensive frac equipment. “These are completions that are short-lived, need minimal treatment to protect the facility from sand, and don’t have to optimize every single barrel because the economics don’t justify it,” Mr Rivas emphasized.

“Operational considerations drive economics,” he said. “In gas-producing areas, for example, stand-alone sand screens can be very efficient if it is a case of pure gas flowing from a rock that doesn’t create much pressure drop or friction. We have casings and perforations in a gas interval, and the screens are like downhole sand filters that keep the sand out of the tubing, assuming we have done everything properly.”

Gravel packs and screens also may be selected in parts of world where frac pack vessels are not available. “It is very tough to pump a frac pack, with all the chemical additives and crosslink gels, without a big, built-for-purpose frac vessel that can roll up to the platform and hook up to the well to do the stimulation,” Mr Rivas noted.

“Frac packs are not ideal in formations where there is an oil/water contact in the sand. In that case, with the oil floating on water and the formation more permeable to water than to oil, we would not want to frac that interval because that fracture will likely extend into the water and water out the well when we put it on production.”

As the industry continues to delve into deeper waters, it is continually faced with technology gaps that necessitate ongoing development of new technological alternatives and tools. Among those is a resin treatment, suited for low reserve and shelf areas, that involves cleaning the grains and gluing them so that they bond together. “This method, which is a replacement for a frac or gravel pack, is limited by the thickness of the interval, but it doesn’t require a frac vessel, is low cost and cuts permeability,” Mr Rivas explained.

“The resin must be pumped from top to bottom in the perforated intervals. If drawdown is put on any untreated intervals, those intervals will produce sand.”

Another emerging technology addresses what the industry calls fines mobility, a subset of sand control that occurs when bits of shale and silt, or fines, that form in highly compressed and pressurized sand formations become mobile as the drawdown is put on the well to allow production.

“If we are unfortunate to have a project that has nice permeability and potential for flow, but the fines are very moveable, we are going to have a real challenge,” Mr Rivas said. “These fines come right through the frac packs, gravel packs and screens and will be produced along with the gas or oil. Moveable fines have ruined some good deepwater projects.”

Frac packs can help in this situation because they control the flux, but there are some techniques, in the form of additives, that are being developed to make the fines stick to the proppant or sand, but out away from the wellbore so they don’t impede flow.

The need for new and better screen designs and better ways to predict the effects of erosion have also become apparent.

“A lot of work still needs to be done on downhole sand screens that can withstand the high rates going through them, as well as the differential pressures that they are asked to stand up to,” Mr Rivas said. “We don’t want to burst the screens, and we’re finding out that screen burst is not quite as well understood as we thought it was.”

In terms of erosion, the industry has learned that the old models for predicting the effects of erosion don’t work very well for sand flow. “Where we are now with erosion modeling is like where we were 20 years ago when we started trying to model fractures,” Mr Rivas said. “There were a lot of different ways to do it, but nobody really knew the best way to do it. This will be a lengthy process to investigate, with long lead times and difficult-to-run computational flow dynamics models for erosion. This is not an off-the-shelf application that a typical completion engineer can look at.”

While sand control and sand management has always been an integral part of completion in the GOM and other

Chevron used Transocean’s dynamically positioned Cajun Express for an initial GOM well test in August 2004, then later to drill and complete subsequent GOM wells.

producing areas with unconsolidated sands, it, along with other well design components, is being pushed to the limit as the industry is challenged by high costs, low permeability and marginal reserves in deeper waters.

“In order to deliver the plan economically and reliably, we need to understand the cost/benefit relationship of every aspect of well construction, of which sand control is one of the big hitters that has an impact throughout the life of the well,” Mr Rivas emphasized.

“We’ve got to look at the whole picture – drilling, completion and production facilities – when making the sand-control decision or we leave money on the table.”

IADC/SPE 128129

Design Methodology and Operational Practices Eliminate Differential Sticking. Fred E Dupriest, Bill Elks, Steinar Ottesen, ExxonMobil.

This paper discusses a successful initiative begun six years ago to eliminate differential sticking across global operations. Since implementation of the stuck-pipe avoidance practices, there have been fewer than seven differential sticking events in over 4,000 wells drilled worldwide.The majority of these occurred early in the implementation, and the causes have now been addressed.

Some level of sticking occurs routinely in drilling operations, but these events become problematic only if the force required to initiate pipe movement exceeds what can be delivered to the stuck point. The operator’s practices are built on the principle that conditions should be maintained at all times that allow the pipe to be pulled free, even if it were to become fully differentially stuck. To maintain this ability to move the pipe, it was necessary to implement a wide range of practices, many of which were not common in the industry.

The paper describes the underlying sticking concepts, the engineering design and field practices and the field results.

IADC/SPE 128311

Liner Drilling Technology as a Mitigation to Hole Instability and Loss Intervals: A Case Study in the Gulf of Mexico. Steven Michael Rosenberg, Deepak Manilal Gala, Wei J Xu, Weatherford International.

IADC/SPE 128311: “Liner Drilling Technology as a Mitigation to Hole Instability and Loss Intervals: A Case Study in the Gulf of Mexico.”

This paper will demonstrate the benefit of liner drilling technology to successfully drill and cement the operator’s 7-in. liner in place, providing an effective solution to hole instability issues resulting from lost circulation in a known catastrophic loss zone in the Gulf of Mexico.

Liner drilling technology was identified as the most appropriate technique for setting the planned 7-in. drilling liner because:

• Documented lost-circulation problems have been minimized or eliminated through prior use of liner drilling technology, largely attributed to the “smear effect”phenomenon.

• The liner system provided for high torsional capability, as well as not being susceptible to premature release due to any sudden pressure increases.

• The 7-in. liner drilling system will minimize or eliminate the nonproductive time for the operation in case of uncontrolled losses.

Ultimately, the correct application of liner drilling technology on this well allowed the operator to reach the intended drilling depth and completion objective. The equipment selection, operation and results of liner drilling will be presented.

IADC/SPE 128901

Total System Optimization Delivered Significant Performance Improvement and Cost Savings in GOM Challenging Salt Section. William Voss, John Kent Aslakson, W&T Offshore; Ian James Thomson, Steven Ralph Radford, Clarissa Thomson, Barrett Buxton, Baker Hughes.

It is well known in the oil industry that there are many drilling challenges associated with salt drilling in the Gulf of Mexico continental shelf. Although many wells have already been drilled through salt, hazard prediction is still not very accurate, which makes extensive planning a huge requirement. While drilling a well through a thick salt body in the shallow waters of the Gulf of Mexico Ship Shoal area, the operator experienced many drilling-related problems, including many downhole tool failures, which led to considerable nonproductive time and financial losses. This paper will focus on the planning and execution of a sidetrack well drilled through salt in the shallow waters of the Ship Shoal area in Gulf of Mexico. This endeavor addressed the problems encountered and allowed the operator to realize a substantial cost savings.

The main drilling challenge in this project was to drill and under-ream efficiently through anhydrite layers embedded in the thick salt body.

The implementation of a multidiscipline total system approach to select the ideal combination of an application-specific rotary steerable system, real-time downhole drilling dynamics tool, drill bit and under-reamer, in combination with appropriate planning, recommendations, drilling procedures and best practices was crucial to deliver significant performance improvement by drilling the sidetrack salt section six days ahead of AFE, which represented USD $2.1 million in savings for the operator.

IADC/SPE 128225

Managing Circulation Losses in a Harsh Drilling Environment: Conventional Solution vs CHCD Through a Risk Assessment. Silvia Masi, Claudio Molaschi, Fabrizio Zausa, Eni; Jean Michelez, Altran.

Conventional drilling techniques used in harsh drilling environments are sometimes impractical or uneconomical. This was experienced while drilling the reservoir section being investigated. This section is characterized by high pressure, with fluids estimated to contain 18%-20% of H₂S and 4%-6% of CO₂, extensive karst/fractures, where severe circulation losses were experienced. That prevented successful drilling using the conventional circulation technique. The pressurized mud cap closed-hole circulation drilling (CHCD) technique was applied and proved to be the most effective method to drill through the lower Carboniferous Carbonate. Where unsustainable losses occur and conventional circulation is no longer possible, the CHCD technique may be used to allow the continuation of drilling.

The CHCD is not a simple, nor an inexpensive system. It is used only when other systems for controlling losses are proven ineffective.

An accurate evaluation of several factors has to be performed. Drilling hazard is the major issue as the primary barrier to well influx is jeopardized, but rig time, material availability and consumption, etc, also have to be considered.

The aforementioned uncertainties can be addressed through risk evaluations by comparing two drilling scenarios of a typical development well, one using CHCD technology and the other using conventional drilling techniques.

Technical Session: Tubulars

IADC/SPE 128931

Case Study: API Box Boreback Stress Relief With Truncated Threads Can Cause Premature Connection Fatigue Failure. Michael Gerdes, Kang Lee, T H Hill Associates.

Stress relief features are added to a rotary shouldered connection (RSC) to increase the fatigue performance of the connection. Although box boreback (BB) modification is an API-approved stress relief feature, numerous cases have been encountered where, under certain operating conditions, the BB feature has been shown to cause premature connection fatigue failures. Subsequently, finite element studies (FEA) were performed to simulate the operating conditions and to determine the impact on fatigue performance of connections with BB feature. This paper presents the details of these case studies, along with the FEA results.

An API boreback feature has traditionally been machined in a manner that results in the crests of the last four or five box threads to be cut short (truncated threads). This results in reduced thread height on the last four to five box threads. Although undesirable, such geometry is widely accepted as an API-approved boreback. Numerous cases of premature box connection fatigue failures were investigated.

This paper presents the case studies where stress relief feature designs have caused premature failures and the FEA studies that have been performed to quantify the effect of stress relief features on connection fatigue performance.

This paper provides the lessons learned from these failure analyses, along with field data, FEA modeling and simulation results. Recommendations on boreback geometry and specific criteria to verify during field connection inspection are outlined for the sake of failure prevention.

IADC/SPE 128316

Deepwater Drilling Challenges Demonstrate Learning Curve With New Connection Technology. Sheldon Perry Langdon, John Kieron Connor, Chevron; Raymond Brett Chandler, Michael J Jellison, National Oilwell Varco.

Chevron’s GOM deepwater drilling projects demand advanced technology, careful planning and precise execution. Located in water depths greater than 4,000 ft, with final well depths exceeding 30,000 ft, Chevron’s GOM deepwater projects have benefited from a new third-generation double shoulder connection (DSC).

A key benefit observed was a reduction in connection damages. Chevron realized up to 90% lower repair costs compared with similar wells using second-generation DSC.

This paper describes the planning, well design, drilling challenges and lessons learned on five deepwater projects. It provides comparison data between the five projects drilled with the third-generation DSC and similar wells that used second-generation DSC.  Comparisons include running and tripping speed analysis and repair cost considerations related to connection handling damage. The paper summarizes drilling efficiency results achieved and provides recommendations to maximize the effectiveness of the new connection technology on future projects.

IADC/SPE 128328

Comprehensive Studies of Aluminum Drill Pipe. Vadim S. Tikhonov, Aquatic; Mikhail Y Gelfgat, Curtis Alan Cheatham, Weatherford International; Aleksandr J Adelman, Consultant.

Low weight, high degree of flexibility and excellent corrosion resistance make aluminum alloy drill pipe ideal for use in drilling ultra-deep and extended-reach oil wells, especially in operating environment with elevated content of aggressive corrosion agents such as CO₂ and H₂S.

This paper presents results of comprehensive studies of the aluminum alloy (Russian Grade) material most widely used for production of 5 ^7/8-in. (147-mm) light alloy improved dependability drill pipe (LAIDP).

Obtained results verify manufacturer’s specifications of 1953T alloy and illustrate that corrosion resistance of 1953T alloy in sea water and elevated hydrogen sulfide and carbon dioxide conditions is higher than that of most steels used for drill pipe manufacturing. They also suggest a high degree of correlation between fatigue testing results and FEA analysis. Results of this study provide further evidence that using LAIDP for drilling wells in such challenging environments is appropriate.

IADC/SPE 129125

Drilling Riser VIV: Fact or Fiction? Michael Tognarelli, Mike Campbell, Dhyan Deka, 2H Offshore.

Vortex induced vibration (VIV) of deepwater drilling risers does occur. This has been demonstrated by BP, which has collected a large amount of drilling riser field measurements over the last 10 years.

Whilst the field measurements have shown that VIV does occur, there have been few, if any, examples of drilling riser fatigue failure due to VIV. The lack of documented failures conflicts somewhat with software predictions, which often predict low fatigue lives due to VIV in high-current environments such as West of Shetland and Gulf of Mexico loop currents. How should the industry deal with this?

Work has already been conducted to develop an approach to reconcile the disparity between VIV software predictions, field-measured VIV and the likelihood of fatigue failure. Using the statistical relationship between software predictions and actual VIV response, a worked example is considered that results in design factors of safety substantially lower than the typical values used in design of 10 to 20.

The paper will document the occurrence of drilling riser VIV in the field and demonstrate a novel approach that can be used to minimize the over-conservatism that is present in VIV design tools whilst maintaining the required level of safety in accordance with industry design codes and standard.

Technical Session: Deepwater I

IADC/SPE 128196

First Year Performance Review for 6th-Generation Drillship. Davis John Mike, Repsol; John Banks, Barry John Rainnie, Stena Drilling.

The challenges of bringing an enhanced deepwater drilling vessel design to market and into operations successfully in a high-activity market are immense. Using a project-based approach with close co-operation between the rig owners, shipyard, third-party equipment suppliers, classification society, Stena Drilling has successfully engineered, built, commissioned and delivered a sixth-generation ultra-deepwater drillship on time. Stena Drilling teamed up with their client, Repsol, and effectively completed  Drillmax’s first two deepwater subsalt ahead of target time, and, more importantly, without causing harm to personnel or the environment. The drillship was delivered to Repsol on 31 December 2007 in Korea, commencing a four-year contract.

The paper will be a case study of Repsol/Stena’s HSE and operational performance utilizing the Stena Drillmax on her first two ultra-deepwater subsalt wells in Brazil and GOM. The paper details the progress of the project through the shipyard, acceptance programs and tracks both operational and HSE performance though its first year of operations.

IADC/SPE 128477

20KSI BOP Stack Development. Melvyn F Whitby, John E Kotrla, Cameron Drilling.

After the introduction of the Cameron 18 ¾-in. 20,000-psi EVO drilling BOP at OTC 2009, this paper will focus on identifying and completing the gap technologies necessary for design and testing of a deepwater 20,000 psi BOP stack.

The paper will identify design methodologies employed in the designing and testing of the BOP and outline gap technologies that must be addressed for completing a deepwater BOP stack.

Taking a bottom-up approach, discussion will focus on the wellhead connector and necessary loads, the drill-through column, choke and kill systems and packaging to allow for use on existing rigs with minimal upgrade intervention.

IADC/SPE 128175

Mono-Diameter Expandable Drilling Liner Applications in Deepwater Drilling. Nitesh Kumar, Roy Marker, Rune Corneliussen, Erik Gustav Kirkemo, Erik Ronneberg, Statoil.

The paper discusses technical aspects of mono-diameter liner extension (MDLE) technology as currently available in different sizes from various vendors to the operators.

The paper does an in-depth analysis on advantages and limitations of MDLEs in deepwater areas from the casing design perspective and strength considerations. A typical deepwater well casing design example has been used to illustrate MDLE’s limitations.

For MDLEs to be useful in a deepwater scenario as a drilling liner, certain prerequisites must be met, as discussed in this paper. If MDLE has to be used for deepwater pre-planning and casing design purpose, a substantial increase in strength (collapse and burst of the pipe) will be required, without which the MDLE will not qualify industry standard casing design criterias. The key issue to address in using this product is meeting the pore pressure requirements.

IADC/SPE 126148

Riserless ReelWell Drilling Method to Address Many Deepwater Drilling Challenges. Mehdi Mir Rajabi, Arnfinn Ivar Nergaard, University of Stavanger; Ove Hole, Ola Michael Vestavik, ReelWell.

In recent years, operators have been drilling wells in ever-increasing water depths. Drilling in deepwater is a daunting task due to both downhole drilling hazards and excessive floating rig packages. Traditionally, these challenging wells are drilled with a low-pressure 21-in. riser stretching from mudline to surface. A huge rig with high weight, space and tensioning requirement is essential to handle this huge and long low-pressure riser in deepwater. As water depth increases, station-keeping for controlling riser deflections within acceptable limits during drilling operations becomes even more difficult. Low-pressure riser has not been designed for controlled pressure drilling technologies. Moreover, it presents several imitations in well control situations.

The Reelwell Drilling Method (RDM) is promising in addressing these deepwater drilling challenges. Reelwell AS, Shell, Statoil and the Norwegian Research Council launched a JIP in 2005 to develop RDM. Many features have been proven throughout verifying tests and studies. The last full-scale test was successfully done in March 2009.

Technical Session: Performance Drilling – Enabling Value Creation

IADC/SPE 128223

Hardware-in-the-Loop Simulations Used as a Cost-Efficient Tool for Developing an Advanced Stick-Slip Prevention System. Age Kyllingstad, Pal Jacob Nessjøen, National Oilwell Varco.

This paper focuses on the lessons learned from hardware-in-the-loop (HIL) testing of an advanced and patent-applied method for curing and preventing stick slip. Stick-slip oscillations are unwanted, self-sustained and periodic torque fluctuations of a rotating drillstring. HIL simulation of stick-slip oscillations uses an advanced dynamic model for the entire rotary system, including the top drive electronics, the motors and the drillstring.

The paper also describes improvements of the advanced stick-slip prevention software, such as automatic parameter settings and a better user interface. Finally, the paper includes results from recent field tests where the advanced stick-slip prevention system has been successfully tested.

IADC/SPE 127094

Weight Distribution in Reaming While Drilling BHAs. Bernhard Meyer-Heye, Georg Peter Ostermeyer, Technische University Braunschweig; Hanno Reckmann, Baker Hughes.

In reaming-while-drilling assemblies, the weight applied to the BHA is distributed between the bit and reamer. To ensure optimized performance during drilling, it is necessary to know the distribution of weight, as well as the distribution of torque in the BHA.

Based on bit aggressiveness and mechanical-specific energy (MSE), an analytical method has been developed to calculate the load distribution in RWD assemblies. Therefore, a new approach to aggressiveness is introduced for the calculation of reamer aggressiveness.

How this technology affects the reamer even when it is applied at the bit will be described in the paper. Data from a field test where weight and torque on bit and on reamer were measured at the same time, in both vertical and directional wells, illustrates the accuracy and validity of the method.

IADC/SPE 128425

Nonproductive Time (NPT) Reduction Delivered Through Effective Failure Investigations. Brad Hubbard, Shabib Kadri, TH Hill Associates; Michael Crotinger, Consultant; James Griffith, Eric Van Oort, Shell.

For offshore drilling operations, tool failures typically account for 5% to 15% of the total cost but can be as high as 30%. Mutual benefit exists for operators and vendors to dedicate the time and effort necessary to consistently perform comprehensive investigations and develop effective solutions to mitigate risk of repeat failures, both regionally and globally. A one-sided or inadequately supported approach to failure response can lead to incomplete analyses and insufficient, biased and localized solutions that may be improperly communicated or implemented, thereby sustaining or creating reliability gaps and allowing further NPT.

In recent years, Shell’s Gulf of Mexico drilling operations formed a dedicated team to establish and facilitate an effective and sustainable approach to failure response.

This paper reviews the approach, process and responsibilities employed, highlighting the mutual benefits for operators and vendors, as well as the impact on NPT reduction in Shell’s operations.

IADC/SPE 128288

Drilling Efficiency and Rate of Penetration: Definitions, Influencing Factors, Relationships and Value. Graham Mensa-Wilmot, Yoseph Harjadi, Sheldon Perry Langdon, Jay Gagneaux, Chevron.

The push to improve drilling efficiency and reduce operational costs has clearly been established in the industry. Regardless of project type or application, drilling efficiency is usually equated to rate of penetration (ROP). Consequently, drilling efficiency is claimed to improve when ROP improves, and asserted to deteriorate when ROP declines. Accordingly, ROP is seen as the parameter that establishes drilling efficiency. This position, in addition to being flawed, is highly inconsistent with operational expectations.

From an operational perspective, ROP needs to be seen as one of several parameters that influence drilling efficiency. The others will be presented and discussed.

To establish its impact on cost reduction, based on the specifics of different projects, this paper will define ROP, as well as categorize the diffferent types.

Depending on project type, ROP is influenced by several factors. As will be seen from its definition, the factors that influence ROP, based on application and/or project type, sometimes create contradictory effects on ROP itself. This condition must be clearly understood, so as to minimize the negative effects.

Consequently, ROP maximization could end up compromising drilling efficiency, if any of the other factors are sacrificed. In addition, all the factors that influence drilling efficiency (including ROP) are directly related; therefore an optimization protocol is required on a project basis. These relationships must be understood in order to continuously improve drilling efficiency.

The paper will establish a clear distinction between ROP and drilling efficiency, as well as their effects on operational efficiency and cost reduction. The arguments and discussions to be presented in the paper will be supported with extensive field data from worldwide operations.

IADC/SPE 128916

An Intelligent System to Detect Drilling Problems Through Drilled Cuttings Return Analysis. A N Marana, Ivan Rizzo Guilherme, J P Papa, São Paulo State University; Marcus V D Ferreira, Kazuo Miura, Francisco Assis Cavalcante Torres, Petrobras.

Cuttings return analysis is an important tool  to detect and prevent problems during the petroleum well-drilling process. Several measurements and tools have been developed for drilling problems detection, including mud logging, PWD and downhole torque information. Cuttings flow meters were developed in the past to provide information regarding cuttings return at the shale shakers. Their use, however, significantly impact the operation, including rig space issues, interferences in geological analysis and additional personel required.

This article proposes a non-intrusive system to analyze the cuttings concentration at the shale shakers, which can indicate problems during the drilling process, such as landslide, the collapse of the well borehole walls. Cuttings images are acquired by a high-definition camera installed above the shakers and sent to a computer coupled with a data analysis system, which aims the quantification and closure of a cuttings material balance in the well surface system domain. No additional people at the rig site are required to operate the system.

Modern artificial intelligence techniques are used for pattern recognition and data analysis. Techniques include the optimum path forest, artificial neural network using multilayer perceptrons, support vector machines and a Bayesian classifier. Field-test results conducted on offshore floating vessels are presented. Results show the robustness of the proposed system can also be integrated with other data to improve the efficiency of drilling problems detection.

IADC/SPE 128905

Electromagnetic MWD Technology Improves Drilling Performance in Fayetteville Shale of North America. Sandeep Shashikant Janwadkar, Christian Klotz, Baker Hughes; Bart Welch, Shane Finegan, XTO Energy.

The Fayetteville Shale is one of newest and fastest-growing shale gas plays gaining significant prominence in North America. This unconventional reservoir is located in the Arkoma basin of Arkansas at depths from 1,500 ft to 6,500 ft and has a thickness ranging from 50 ft to 325 ft. Drilling horizontal wells coupled with hydraulic fracturing makes this reservoir highly prolific and comparable to the Barnett Shale.

However, the area presents numerous drilling challenges. Loss circulation, wellbore instability, high torque and drag (T&D), along with low penetration rates hampered drilling the curve and lateral sections.

To address these challenges, a detailed engineering analysis was performed utilizing a proven drilling optimization procedure. As a result of the study, engineers determined that pumping loss circulation material (LCM) to control fluid losses affected the performance of downhole measurement-while-drilling equipment. Drillstring modeling indicated that wellbore tortuosity resulted in high T&D and inefficient transfer of weight on bit. Existing standard mud-pulse technology could not operate efficiently while drilling with loss circulation, no fluid returns or high LCM concentrations. Wired pipe technology is typically cost-prohibitive in this application.

The improvements resulted in 28% to 39% reduction in drilling time to reach target depths. The authors will describe the significance of applying principles of electromagnetic technology, torque and drag analysis and bit design to improve drilling performance.

Technical Session: Special Techniques

IADC/SPE 128685

Successful Development and Field Qualification of a 9 5/8 and 7 in. Rotary Steerable Drilling Liner System That Enables Simultaneous Directional Drilling and Lining of the Wellbore. Arne Torsvoll, Jafar Abdollahi, Morten Eidem, Tore Weltzin, Arne Hjelle, S. Rasmussen, Statoil; Sven Krueger, Sascha Schwarze, Carsten Freyer, T Huynh, Tore Sorheim, Baker Hughes.

Many oil and gas operators around the world are faced with similar operational risks when entering the mature field phase. Narrow drilling margins, hole collapse and lost circulation are among the challenges that must be dealt with safely and economically.

This paper describes a successful approach to overcoming these challenges developed through close cooperation between the operator and the oilfield services company.

Providing an overview of the concept, the technology and the operating principles of the 8 ½ x 12 ¼ in. and 6 x 8 ½ in. advanced steerable drilling liner system, the paper will highlight the development and the testing process leading to the successful execution of the world’s first steerable drilling liner application in the Norwegian Sector of the North Sea.

Included in the discussion will be a description of the system’s testing and qualification of the two system sizes (9 ^5/8-in. and 7-in. liner) at the service company’s experimental test rig according to the operator’s test program to guarantee that all specific needs for a first commercial deployment have been achieved.

IADC/SPE 128266

An Experimental and Numerical Approach to the Prediction of Collapse Resistance for Expandable Tubulars. Jun Agata, Eiji Tsuru, Mitsuru Sawamura, Hitoshi Asahi, Hidefumi Tsugihara, Nippon Steel.

This paper summarizes the results of a study aimed at understanding the governing factors in the collapse of expandable tubulars and constructing the prediction method of post-expanded collapse resistance. Post-expanded collapse resistance is one of the essential properties for expanded tubulars; thus a reliable prediction technique is useful for the casing design using expandable tubulars. However, the collapse formulas widely used are not applicable for post-expanded expandable tubulars since the governing factors of collapse are considerably varied by pipe expansion and out of the coverage of conventional formulas.

To solve this problem, full-scale expansion and collapse tests were performed to investigate the effect of material properties, expansion ratio and axial restriction simulating the unexpected stuck in oil wells on the collapse resistance. Then considering the governing factors of collapse of pre-expanded pipes, a new finite element analysis model was developed to evaluate pipe expansion and subsequent collapse strength consistently.

The test results demonstrated that the post-expanded collapse resistance is significantly degraded by the increase in diameter-to-thickness ratio and the deterioration of various governing factors of collapse, which are compressive yield stress, residual stress and thickness eccentricity. However, the axial restraint suppressed the deterioration of collapse resistance regardless of the much higher reduction in wall thickness, which can be canceled out by the relatively higher yield stress and low residual stress under the restraint condition.

In conclusion, the effects of the governing factors of collapse and expansion condition on the collapse resistance were clarified for expandable tubulars in the wellbore. Furthermore, the numerical method to evaluate the expandable tubular collapse resistance was established considering the variations of governing factors of collapse. We expect the results to contribute to our understanding of expandable tubular collapse and form the technical basis for improving the reliability of expandable tubular casing design.

IADC/SPE 128219

Spud to Reservoir With Casing While Drilling (CWD)/Polycrystalline Diamond Compact (PDC) Drillout Technology Using an Automated Drilling Rig. Robert Te Gussinklo, Northern Dutch Drilling; Brian Allan Hepp, Dick Swart, Northern Petroleum; John Hugh Wingate, Baker Hughes.

A vertical exploration well to be drilled top to bottom using CwD/PDC drill out bits on a newly commissioned automated land drilling rig. Three hole sections, planned TD 2,550 m. The 12 ¼ section (0-850 m) was to be drilled using CwD (on 9 ^5/8-in. casing). The 8 ½-in. section (850 to 2,000 m) was to be drilled in one run with a PDC bit. The bit would also drill out the cemented 12 ¼-in. CwD bit. The 7-in. casing was run with an 8 ½-in. CwD bit. The 8 ½-in. CwD bit would allow obstructions to be drilled away, ensuring the casing was set at planned depth. The cemented 8 ½-in. CwD bit and 6-in. section (2,000 to 2,550 m) to be drilled in one PDC run, CwD / PDC drill-out technology was used to successfully drill down into the reservoir (2,418-m total length). CwD was used to drill and case the 12 ¼-in. hole section with 9 ^5/8-in. casing to a depth of 780 m. The 8 ½-in. bit successfully drilled out the 12 ¼-in. CwD bit and drilled on to section TD at 2,075 m. Then the 7-in. casing with an 8 ½-in. CwD bit was successfully set at depth.

There were no lost-time incidents on the newly commissioned rig. The automated pipe-handling system and CwD with its simplified BHA enabled a safe start to the well to a crew unfamiliar with a new rig system. These technologies enabled reduced tool/pipe handling and tripping events.

This was the first well drilled with a recently commissioned automated drilling rig using CwD and PDC drill-out technology. The well included the first CwD run in Holland.

IADC/SPE 127764

Are You on the Right Track With Casing Milling? Innovative Precision Milled Windows Offer Improved Casing Exit Reliability for Sidetracking and Multilateral Completions. Calvin B Ponton, Justin Mark Roberts, Steven R Fipke, Andrew John Cuthbert, Halliburton.

Multilateral wells offer many benefits over conventional wells, including reduced overall drilling costs, lower environmental impact, increased total recovery, greater access to production intervals and subsequently improved well production rates. However, obtaining a good-quality casing window through which an additional lateral branch can be successfully drilled and completed can be difficult to achieve.

Track-guided milling systems have emerged as an effective and accurate method by which to control casing window geometry. This paper will focus on recent advances in track-guided, precision window milling technology and its impact on multilateral well design.

A good-quality casing window, with precisely controlled length and width, ensures that drilling and completion equipment are without problems and facilitates repeatable re-entry access to both the main bore and the laterals in future interventions. The quality of the casing window is just as critical in multilateral wells as in conventional sidetracking or whipstock operations.

Advances in modern casing milling technology are pioneering improved multilateral well designs.  Multilateral wellbore junctions can now be placed in deep, high-angle wells without compromising drilling or completion operations; a major Middle East operator has drilled several multilateral wells using a track-guided milling system to create improved casing windows.

IADC/SPE 128926

Improved Drilling Performance and Economics Using Hybrid Coiled Tubing Drilling Unit on the Chittim Ranch, West Texas. Brady Louis Littleton, Scott Nicholson, Curtis G Blount, ConocoPhillips.

A performance and cost improvement was achieved with the application of hybrid coil-tubing drilling on the Chittim Ranch in Maverick County, Texas. The drilling performance was seen with the use of a surface top set rig and a coil-tubing rig to drill the production hole. Compared with conventional drilling, coil-tubing drilling has reduced the time to complete a well by 60%. This increase in drilling performance coupled with a turnkey contract resulted in a 30% cost reduction per well. Finalized project data will show that field performance was better than the planned performance.

IADC/SPE 128314

Multilateral Wells Reduce CAPEX of Offshore, Subsea Development in Australia’s Northwest Shelf. Brett Clifford Lawrence, Apache Energy; Mike Zimmerman, Andrew John Cuthbert, Steven R Fipke, Halliburton.

Multilateral technology reduces the number of production well slots required to effectively drain a reservoir, resulting in time and cost savings. Having fewer discrete subsea wellheads translates into a major reduction of investment capital in offshore environments. Reducing the cost of the subsea infrastructure is the primary benefit of multilateral well architecture, but additional benefits include reduced top-hole drilling costs, reduced project execution time and hence accelerated production, increased PI and fewer rig moves.

This paper will discuss the lessons learned from nine horizontal TAML Level-5 dual lateral wells drilled offshore in the Van Gogh Field. It is an excellent example of a field that was developed from start to finish with multilateral technology as the enabler. The project was successfully completed in Q2 2009 with a significantly lower capital investment than would have been required to develop the field with single horizontal wells.

Technical Session: Deepwater II

IADC/SPE 128190

Drilling Deep in Deep Water: What It Takes to Drill Past 30,000 ft. Crispin Chatar, Riaz R. Israel, Schlumberger; Andre John Cantrell, Devon Energy.

Today, operators are being pushed more than before, not just to explore deeper prospects but also to get there efficiently. The future of the industry depends on it. There are new questions the industry is asking about the deepwater: What is different about drilling deep in deepwater operations? What does it actually take to drill the deepest wells in the world today? Currently, there are only a handful of personnel at both operating comopanies and service companies with the knowledge and experience to execute these wells. This paper will discuss the challenges of planning and drilling directional wells in excess of 30,000 ft true vertical depth (TVD) and look at lessons learned by major deepwater Gulf of Mexico operations that have successfully drilled wells beyond this mark and are continuing to push the envelope further. These wells have held, at one time or another, records for deepest wells drilled in many categories in recent years.

The paper will discuss methodologies and general rules for planning these wells, related to torque and drag, side forces, slip crushing, drillstring and landing string design, well plan trajectory design, directional control, salt drilling, downhole tools and other aspects of interest for these types of operations. Many of these items will be supported by case studies from actual wells drilled in the GOM. The paper will conclude by identifying additional resources that are available and new and emerging technologies that would be required if we are to take these wells beyond the current limits of today’s deepwater drilling. This paper will contain invaluable information and knowledge-sharing for new engineers who want to plan deep wells in deepwater.

IADC/SPE 127687

Opportunities and Challenges of Deepwater Subsalt Drilling. Rohit Mathur, Baker Hughes; Nancy Seiler, Anadarko; Ananth Srinivasan, Nesny O Pardo, Baker Hughes.

Drilling wells to depths greater than 25,000 ft will continue to present geologic and economic challenges for deepwater operators. These capital-intensive projects require acute attention to maximizing drilling efficiency and mitigating risk.

Using several case studies, this paper describes recent deepwater subsalt exploration activity and discusses the challenges of drilling through the salt. Through close collaboration between the operator and drilling service provider, efforts to push rig and tool limitations successfully resulted in an increase in drilling efficiency.

IADC/SPE 128192

Overcoming a Difficult Salt Drilling Environment in the Gulf of Mexico: A Case Study. Crispin Chatar, Sushil Mohan, Mark D Imler, Schlumberger.

More than a decade ago, few companies successfully penetrated and intentionally drilled large salt sections encountered in the Gulf of Mexico. It was common to find hole instability, stuck pipe, lost in hole and countless other problems leading to excessive nonproductive time when drilling salt. Since then, many techniques have been adopted to successfully drill many of the large salt formations encountered in the Gulf of Mexico. However, there still exist specific exceptions where, due to nature of formation in the area, drilling can still be challenging.

This paper will concentrate on the case study and the lessons learned on the salt section of what is considered difficult deepwater wells in the Gulf of Mexico. Key salt-drilling challenges are identified beyond traditional salt-drilling difficulties.

The paper also discusses the strategies used to overcome these key challenges that continue to exist, such as non-homogeneous salt formation, shock and vibration and salt inclusions. A focus is adopted on that application of new and emerging technologies and techniques for drilling in similar environments with focus on drilling parameter optimization, BHA tendencies and stuck pipe analysis. This paper concludes with a case study that compares in detailed the expected results prior and after the optimization measures are adopted.

IADC/SPE 128405

Salinity-Based Pump and Dump Strategy for Drilling Salt With Supersaturated Fluids. Thomas Jay Akers, ExxonMobil.

Riserless drilling with weighted mud systems, commonly referred to as a “pump-and-dump” drilling strategy, is an established drilling technique used on deepwater wells with shallow hazards. Large holes and high flow rates result in very large volumes of fluid being required to drill to TD, circulate the well clean and cement the conductor casing string. Fluids management becomes a major issue in the riserless hole section. In the Gulf of Mexico, mud is often densified in excess of well requirements, then blended with seawater in a “cut back” operation to reach the desired density to pump downhole.

When riserless drilling into salt, a pump-and-dump strategy is often used. Dilution with seawater, however, results in an undersaturated fluid. This fluid leaches the salt, resulting substantial hole enlargement. The hole enlargement can result in poor cementing jobs that require remediation or even an additional string of casing. A unique operation has been employed in the Santos Basin of Brazil where a supersaturated brine fluid was used to conduct a pump-and-dump operation with the goal of drilling with a saturated brine fluid and minimizing hole enlargement.

This paper details the planning of the operation, fluid design and pilot testing. Fluids management, equipment rig-up and results are discussed in detail. The operation has been successfully executed twice, with both operations achieving the set objectives for the wells. Unforeseen complications that were encountered are discussed along with lessons learned that have been applied to subsequent operations.

IADC/SPE 128166

Case History: Deepwater Drilling Campaign on the Norwegian Continental Shelf in 2008 and 2009: A Success Story. Stian Haugland Cruickshank, Erik Gustav Kirkemo, Glenn Kaare Gabrielsen, Oystein Hovden, Reino Tommy Tryland, Roy Marker, Statoil.

Statoil drilled six deepwater wells, including one sidetrack, on the Norwegian Continental Shelf in 2008 and 2009. The semisubmersible rig Transocean Leader was used for these drilling operations.

All the wells were drilled and abandoned in a total of 390 days, some 120 days ahead of schedule. Gas and/or condensate were discovered in five out of these six wells. The wells were all drilled with higher efficiency compared with previous deepwater wells drilled on the Norwegian Continental Shelf. The water depth for the wells ranged from 950 m to 1,350 m.

This paper describes how deepwater exploration wells were planned and successfully completed with the Transocean Leader. Good teamwork between offshore and onshore contributed to this success story.

IADC/SPE 127817

Riserless Drilling with Casing: Deepwater Casing Seat Optimization. Kenneth James Kotow, David M Pritchard, Successful Energy Practices.

This technical submission is a follow-up to “Riserless Drilling with Casing: A New Paradigm for Deepwater Well Design,” OTC 19914, which discussed the need for a deepwater well design change for GOM and proposed a well-design concept based on setting the first two casing strings significantly deeper than current practice. This would result in the well design having more contingency casing options and larger hole sizes to successfully drill the narrow operating window typically experienced in deepwater wells.

This follow-up submission will thoroughly discuss and demonstrate the feasibility of using drilling with casing for shallow hazard mitigation, which allows the first two casing strings to be set deeper. It will further discuss how drilling with casing improves the near-wellbore shallow fracture gradient while providing better dynamic ECD control of potential shallow-water or gas flows. This will include summarizing drilling-with-casing case histories that are similar to GOM deepwater environments. Furthermore, there will be a discussion highlighting some the conceptual technological innovations available to allow drilling with casing in a deepwater riserless situation.

The second part will outline feasible well casing designs that could improve the possibility of deepwater GOM wells meeting their key well objectives with increased frequency, and reverse the lack of learning curve that was clearly demonstrated in the aforementioned paper.

Technical Session: Managing for Performance

IADC/SPE 128296

Novel Applications of Drilling Simulators in Student Recruitment, Teaching and Research Programs. Ramadan Mohammed Ahmed, University of Oklahoma; John Rogers Smith, Louisiana State University; Veronica Beatriz Bohorquez, William L Koederitz, National Oilwell Varco.

IADC/SPE 128296: “Novel Applications of Drilling Simulators in Student Recruitment, Teaching and Research Programs.”

Drilling simulators have been used extensively for teaching, especially well control, and for analyzing drilling operations, such as cementing and the impact of drillstring dynamics. This paper describes new approaches being taken at two universities to develop and use drilling simulators. Although the approaches are different, both are designed and developed for use in recruiting and teaching students and conducting simulation studies. The design and capabilities of both drilling simulators and how they are integrated into the petroleum engineering educational programs are described.

These novel drilling simulators are expected to have a significant impact on the recruitment and retention goals of these university petroleum engineering programs. The impact of using the physical drilling model in recruiting and undergraduate exercises will be observed by faculty and assessed with surveys and graded exercises, respectively. Conclusions regarding the impact of these early applications will be provided. Plans for evaluating the broader impacts resulting from future uses of these systems include interviews of students, faculty, recruiters and industry personnel involved, and observing and grading student performance on exercises, lab reports and tests.

A crucial challenge of the drilling industry is finding the right people for drilling engineering careers, then educating them to be as productive and motivated as possible once they start their careers.

IADC/SPE 128716

Well Delivery Process: A Proven Method to Improve Value and Performance While Reducing Cost. John P De Wardt, De Wardt and Company.

A well delivery process defines a set of activities along a time line to plan, execute and close out a well. The most advanced versions of this process include tools and techniques that create robust plans, including risk and uncertainty management, technical limit focus and stretch goals, probabilistic time and cost estimating, detailed scheduling, drill/complete the well on paper and similar group exercises. Stage gates are included that provide review points, which are usually matched to a corporate capital value or opportunity realization process. The most advanced form of the process incorporates best practices from lean manufacturing. The paper will describe the development of a well delivery process from the mid 1990s through today.

Lessons learned will be described, including the correlation of performance with robust risk assessment. Recommendations on the key drivers for a successful well delivery process will also be described.

A best practice and robust well delivery process is essential for high-cost drilling operations and chal: lenging drilling environments, whether exploration wells or in-fill drilling in depleted reservoirs to small hydrocarbon accumulations. This paper will provide an essential guide to drilling managers wishing to develop a well delivery process.

IADC/SPE 128442

Anchor Handling and Rig Move for Short Weather Windows During Exploration Drilling. Arild Saasen, Norsk; Michael Simpson, AGR Petroleum Services; Bjorn Thore Ribesen, DNO.

The paper describes field experience with a method for efficient anchor-handling and rig move during North Sea exploration drilling campaigns. Cost contribution of anchor handling in itself may be in the order of magnitude 10%-20% of the total well cost of offshore exploration wells. Including rig-move costs, the anchor handling and mooring costs represent possibly the most singularly costly operation in exploration drilling.

The paper describes a typical anchor-handling operation, including a rig move operation. Thereafter a field case will be presented, including an innovative method for combining anchor pickup, rig move and presetting.

As will be described, a traditional anchor-handling operation would have resulted in two days waiting on weather in addition to the extra time spent on anchor handling because the weather conditions changed unfavorably. The paper also describes the challenges of retrieving preset anchors.

IADC/SPE 128865

RCM Principles Provide Predictive Asset Maintenance Benefits, Cost Savings. Frank Breland, Diamond Offshore Drilling; James Guy, Pride International; Max Masters, Bronco Drilling; Nathan Dale Kinert, Ashe Menon, National Oilwell Varco.

Since its inception, the drilling industry has grown accustomed to a “firefighting” culture, facing and solving problems as they occur. A study on reliability-centered maintenance (RCM) proposes to move the industry toward a “fire prevention” culture by transferring technologies from industries like aerospace, automotive and downstream petroleum to develop smarter equipment monitoring and management systems that enable the improved design, construction and maintenance of rig equipment. RCM principles have yet to be applied in the drilling industry because of the harsh conditions and repeated movement that equipment is subjected to over a typical life cycle.

This study involves identifying equipment on drilling rigs using field-proven radio frequency identifier (RFID) tags and acoustic and vibration sensors to measure operational deviations from the baseline. The RFID tags ensure accurate historical data is obtained regarding equipment location and movement. To establish trends, real-time rig equipment data is collected and charted. A web-based application is used to monitor and manage equipment maintenance. Failures that result in maintenance-related downtime are added to the database, and the trend is updated. A data analysis model developed using statistical analysis software narrows down potential causes and identifies problem sources.

This study clearly demonstrates that significant economic benefits can be realized by applying RCM practices using smart equipment monitoring and management systems for better preventive rig equipment maintenance. Moreover, RCM application using rig equipment data helps achieve asset maintenance goals, including greater safety, longer life and higher equipment availability and reliability, while simultaneously enabling better quality product development with greater cost effectiveness.

Technical Session: Cementing and Zonal Isolation

IADC/SPE 128734

Large-Volume Cement Squeezes as Cost-Effective Solutions for Servere Loss Zones. Devendra R Algu, Robert Loran Galey, Miles Barrett, Michael Humphries, Shell.

Loss circulation is commonly induced while drilling extended-reach wells through depleted intervals.  The combination of narrow margin between formation pore pressure and fracture pressure makes loss circulation inevitable in many wells. Pretreatment of the drilling fluid with loss circulation material while drilling and wellbore strengthening techniques have successfully reduced instances of high-rate, large-volume (greater than 1,000 bbls) losses.

If losses are severe, this trip may not be possible without risk to well control. Second, it is difficult to restore and maintain wellbore strength to a level equivalent to the integrity prior to losses, especially if substantial open-hole drilling time is required to reach the next casing point.

This paper presents the design strategy, formulations and testing requirements, placement techniques and procedure, and other practices utilized in successful large-volume cement squeezes to remediate severe, high-rate, large-volume losses. Results from three case studies will be presented to illustrate successful application of this treatment approach.

IADC/SPE 127885

Using Surfactant Nanotechnology to Engineer Displacement Packages for Cementing Operations. Ryan Van Zanten, Bridget Lawrence, Stephen Joseph Henzler, Halliburton.

Removing oil-based drilling fluid residue is crucial to developing an excellent cement bond between casing and formation.

Laboratory testing led to the development of a surfactant-based micro-emulsion forming cement spacer. The micro-emulsion spacer water-wets more effectively than previously used solvent/surfactant spacers, eliminating the use of solvents in the cement spacer. The elimination of solvents allows for a more environmentally friendly solution. Mixing this spacer with oil-based drilling fluid does not change the wettability of the bulk fluid, allowing it to be remixed with the remaining fluid.

Several different field trials in the Rocky Mountain region have been run, showing improved cement bond logs. Operational personnel identified that the surfactant package replaced the use of two existing surfactant packages, eliminating mixing errors and minimizing logistical issues. Initial lab tests were done with local field fluid samples to compare wettability results. Improved wettability was achieved on different fluid systems, diesel-based and synthetic oil-based. The operator approved the use of new micro-emulsifier on several wells. After the operator had run bond logs, results were compared to wells with similar job designs and wellbore conditions. Improved bonds were shown in the wells where the new surfactant package was applied.

IADC: 128226

Self-Healing Cement System – A Step Forward in Reducing Long-Term Environmental Impact. Sylvaine Le Roy Delage, Schlumberger. Alain Comet, Andre Garnier, Jean Louis Presles, Total; Helene Bulté-Loyer, Philippe Paul Andre Drecq, Iker Unanue Rodriguez, Schlumberger.

The short-term concerns about the environmental impact of drilling operations can be addressed through careful management of surface operations. However, of greater concern are the long-term impacts of unplanned events during the life of the well. The number of wells that leak or show sustained casing pressure remains a high percentage of the total number of wells worldwide. Loss of zonal isolation, especially when the leaks are vented to surface, poses a clear environmental risk because of the potential emission of greenhouse gases, such as methane.

This study illustrates that designing a cement composition with self-healing properties to hydrocarbons  and more specifically to gas requires expertise, know-how and the development of adequate experimental set-ups to assess self-healing properties. Operational practices are reviewed, which confirms that standard field mixing and pumping processes are adequate for properly placing such cements.

IADC/SPE 128304

Well-Integrity Monitoring and Analysis Using Distributed Acoustic Fiber Optic Sensors. John William Hull; Hifi Engineering; Lance Gosselin, EnCana; Kevin Borzel, Husky Energy.

Evaluating well integrity (i.e., flow of fluids or gas) from behind casing can be challenging using existing single-mode analog sensors. They offer limited representation, and data acquisition can be time-consuming. Further, traditional processing algorithms such as Fourier Transforms are not responsive to non-stationary, non-linear events such as random, low-volume leak signatures. Recent advancements in both fiber-optic distributed acoustic sensors (DAS) and processing algorithms stand to significantly simplify downhole low-rate leak detection. This paper will explain the capabilities and limitations of this monitoring approach.

The integrated well monitoring and analysis system offers a more comprehensive solution. Compared with traditional technologies, future remedial strategies were often strategically more accurate, especially when low leak rates were involved. It is anticipated that engineers will be able to locate problematic leaks with higher confidence and save money by reducing the number of failed interventions. Similarly, the need for experienced, highly trained log analysts will be reduced. Applications for this information may include: low-rate leak detection through casing, pipe integrity failures, zonal isolation issues, long-term well monitoring, carbon storage and sequestration, evaluating intervention effectiveness, and locating multiple source leaks.

Technical Session: Managed Pressure Drilling

IADC/SPE 128424

Evaluation of Alternative Initial Responses to Kicks Taken During Managed Pressure Drilling. Majid Davoudi, John Rogers Smith, Bhavin M Patel, Jose Eduardo Chirinos, Louisiana State University.

An industry-supported research project has completed its evaluation of alternative initial responses to kicks taken during managed pressure drilling (MPD) operations using the constant bottomhole pressure (CBHP) method. The evaluation is the first phase of a study that is intended to provide a basis for comprehensive and reliable well control procedures for MPD operations.

The results of several hundred simulations have been compared based on the ability to stop formation flow, ability to confirm flow was stopped, risk of lost returns, risk of excessive surface pressures, and practicality and timeliness of application. This comparative evaluation is exemplified with plots of key responses and tables of the most important results.

These results support the conclusion that although there is no one best initial response to all kicks, there are three that should be broadly applicable. The selection of the most practical application is shown to depend on well conditions and the equipment being used. Potential advantages and constraints on the use of these responses are also explained.

Consequently, no industry standard procedures currently exist for MPD well control. This work provides the first comprehensive study of many of these combinations of kick causes and potential initial responses.

IADC/SPE 128222

High Performance and Reliability for MPD Control System Ensured by Extensive Testing. John-morten Godhavn, Statoil; Kjetil Arne Knudsen, Halliburton.

This paper presents the preparations for an MPD operation at Gullfaks in a narrow drilling window. A control system was developed to control the downhole pressure within a narrow pressure window. The control algorithms were developed using a simple non-linear dynamic model of the choke and the annulus volume.

The control system was tested both in computer simulations of this model and in two experimental set ups: one test in a 1-km horizontal flow loop in Houston and a second test in a vertical test well in Dallas. Water was used in both these tests. The paper also includes results from the offshore acceptance test in a cased well using oil-based mud. The main purposes of the modeling, computer simulations and onshore and offshore testing were to verify the MPD solution as much as possible and to save rig time. The set of normal drilling operations performed in the preparations included connections, rate changes, pressure changes, start and stop of pumps, swab and surge, drillstring rotation changes and connections. New functionality was developed to make a more robust system to handle contingencies.

IADC/SPE 128923

New Automated Control System Manages Pressure and Return Flow While Drilling and Cementing Casing in Depleted Onshore Field. Julio Cesar Montilva, Shell; Paul Douglas Fredericks, Ossama Ramzi Sehsah, At Balance.

Liner drilling is a proven method in South Texas to eliminate lost circulation by eliminating swab-and-surge effects and heavy trip margins. In the McAllen and Pharr fields, the amount by which the mud and thereby the risk of losses can be reduced with liner drilling is limited because the sands can be more permeable and more likely to flow with statically underbalanced (SUB) mud. Automated MPD is used in the McAllen and Pharr fields to reduce the mud weight to as low as possible, even below pore pressure if necessary, and prevent influx from the more permeable reservoirs.

Automated managed pressure drilling (MPD) has enabled Shell to continue using liner drilling technology by drilling with SUB mud and reducing the ECD. Managing constant bottomhole pressure while drilling, making connections and during trips has helped eliminate lost circulation, stuck pipe and unplanned influx.

IADC/SPE 128648

Drilling a Challenging HPHT Well Utilizing an Advanced ECD Management System With Decision Support and Real-Time Simulations. Rolv Rommetveit, Sven Inge Odegard, Christine Nordstrand, eDrilling Solutions; Knut Steinar Bjorkevoll, P Cerasi, H Helset, SINTEF; Mikkel Fjeldheim, Stein Tjelta Havardstein, Total.

A very challenging HPHT well has been drilled utilizing an advanced ECD management system including real-time simulations, early diagnosis of upcoming problems and real-time simulations using state-of-the-art models. The system uses all available real-time drilling data (surface and downhole) in combination with real-time modeling to monitor and optimize the drilling process. This information is used to visualize the wellbore in 3D in real time. It has been implemented in Total E&P Norge TASC (Total Activities Support and Collaboration) Center in Norway.

Experiences from the drilling, as well as use of the ECD management system, will be summarized and presented. The supervision and diagnosis functionalities have been useful in particular.

Technical Session: Bit Technology

IADC/SPE 128741

Hybrid Bits Offer Distinct Advantages in Selected Roller-Cone and PDC Bit Applications. Rolf Pessier, Michael Damschen, Baker Hughes.

This paper describes a new generation of hybrid bits that are based on proven PDC bit designs with rolling cutters on the periphery of the bit.

Laboratory and field results will be presented that compare the performance of hybrid bits with that of conventional PDC and roller cone bits. A hybrid bit can drill shale and other plastically behaving formations two to four times faster than a roller cone bit by being more aggressive and efficient.

IADC/SPE 128911

Improving Horizontal-Well Drilling Performance With PDC Bits Designed to Increase Aggressiveness Through the Run. Chad Beuershausen, Thorsten Schwefe, Cara Weinheimer, Baker Hughes; M Kramer, Devon Energy.

A substantial development effort, backed by drilling simulator and field testing, has delivered a directional PDC drill bit optimized for drilling the curve and lateral sections of horizontal wells. The PDC drill bit employs a new technology that controls the aggressiveness, or the relationship between weight on bit (WOB) and the reactive torque, of the bit in specific portions of the well and delivers reduced drilling and operating costs.

With changes to the North American natural gas market, the need to reduce cost and eliminate bit trips has increased substantially over the past year.  Operators in North America oil/gas shale plays have migrated to drilling a combined curve and lateral section with a single bit to reduce operating expenses and rig time.  .

The goal for this innovative feature is to control the aggressiveness at the beginning of the curve section of the well, where control drilling is generally used to achieve the desired build-up rates.

This paper demonstrates how selectively changing the aggressiveness of the PDC drill bit in the curve and lateral sections can increase on-bottom drilling time and decrease operating expenses due to increased toolface control and increased rate of penetration.

IADC/SPE 128486

New Cutter Technology Redefining PDC Durability Standards for Directional Control: North Texas/Barnett Shale. Ryan Neil Baker, Yuelin Shen, John Zhang, Smith Technologies; Scott David Robertson, Chesapeake Energy.

It is critical to optimize borehole placement and maximize total lateral footage within the producing horizon to enhance project economics. Additionally, in the vertical/build section, the operator must drill the sharp, abrasive Atoka sandstone and Bend conglomerate. These formations usually require several bits/trips to complete the hole section. These formations have historically been drilled with roller cone bits because standard PDC bits/cutters do not have the required wear and impact resistance to withstand the punishment of the downhole environment without sustaining ROP killing cutter damage. The operator required new cutter technology to efficiently drill the hardest, most abrasive sections of the Atoka sand and Bend conglomerate. The PDC bit body also needs to provide superior directional control to efficiently deliver the complex borehole geometries.

To solve these issues, the service provider initiated an R&D effort to analyze the levels of frictional heat generated at the rock/cutter interface. This high temperature is a major factor limiting PDC application in challenging hard/abrasive formations.

The case studies will document significant performance improvement and reduced cost per foot in directional intervals from drill-out to kick-off point. The performance improvement includes three footage/depth out records that substantially decreased number of hours to complete the interval, translating to substantial cost savings.

IADC/SPE 128950

Application-Specific Bit Technology Leads to Improved Performance in Unconventional Gas-Shale Plays. Matt Isbell, Dan Eugene Scott, Mark Freeman, Baker Hughes.

Unconventional gas plays in Texas, Oklahoma and Louisiana have become increasingly important. Operators have been able to produce unconventional gas in these shale formations through better well profiles and completion/fracture technology. One key to the continued success of these fields is reducing the cost to drill these wells with the current depressed pricing of natural gas. Two general types of drilling programs are vertical/curve/horizontal profiles and more complex wells drilled from a pad. A new application-specific bit design package has been developed for these applications. This new design comprises features that include improved stability, steerability, optimized hydraulics, depth-of-cut control, diamond volume management, and cutters optimized for wear and durability.

The challenge of this vertical/curve/horizontal program is to combine two intervals into one bit run, thereby reducing the number of bits from three to two, improving the economics in drilling the well. In complex well profiles, steerability and durability are critical, and many of these intervals have been drilled with roller cone bits until recently. The advent of the application-specific bit designs has enabled operators in these programs to replace multiple roller cone bits with one PDC bit.

This paper will present case studies from multiple independent operators showing the improvement of drilling performance, which has led to significant cost savings through reduced drilling time and fewer trips.

IADC/SPE 128161

Advanced Modeling Technology: Optimizing Bit-Reamer Interaction Leads to Performance Step Change in Hole Enlargement While Drilling. Uyen Tran Partin, Molly Compton, Gail R Nelson, Denise Livingston, Patrick Davis, Smith Technologies.

The increasing necessity for hole enlargement-while-drilling (HEWD) technology has resulted in an essential need for engineers to fully understand the interaction between the drill bit and the hole-opening tool. Inefficiency and damaging bit/BHA vibrations, caused by improper bit and reamer selection drilling through interbedded formations and formation transitions, are a leading cause of inconsistent performance, including excessive torque, low ROP and downhole tool failures.

The technology for this engineered approach is a comprehensive 4D finite element model that couples laboratory results with a robust simulator that calculates the drilling system’s dynamic performance from bit to surface in a time domain. Unlike other modeling programs that assume the contact forces between the cutter and rock, this advanced model utilizes exact cutting structure details coupled with the laboratory-derived rock mechanics to accurately predict the performance of the bit and reamer with the entire drillstring. The effects of BHA and drilling parameters on vibrations, ROP and directional tendency can be quantitatively evaluated.

The paper will compare simulated results with field-recorded values for validation and discuss the technology and engineering involved in optimizing the drilling performance.

IADC/SPE 128575

Understanding the Contributions of Primary Stability to Build Aggressive and Efficient PDC Bits. Danielle Fuselier, Chaitanya Vempati, Jack T Oldham, Suresh Patel, Baker Hughes.

In the fast drilling environment, the bit passes from the softer formation to the harder interbedded stringers. In the hard-to-drill rock environments, the bit is drilling at low depths of cut. In both of these environments, it is critical to the overall performance in both rate of penetration (ROP) and distanced drilled that the drill bits exhibit stability that is dependent on how the cutting structure interfaces with the formation (primary stability) and keeps the bit from being perturbed when drilling.

This paper will investigate how increasing primary stability can improve both the aggressiveness and efficiency of the bit, and gain performance that cannot be achieved with bits that use secondary stability as part of the design methodology to stabilize or otherwise protect the cutting structures in these drilling environments. This paper will also outline a rigorous product development effort with testing both in a laboratory setting as well as in the field.  Using aggressive cutting structures to drill these two environments can increase performance if the bit has a strong primary stability signature, as demonstrated by the test protocols used in this development effort.

Technical Session: Drilling Fluids

IADC/SPE 128728

Wellborn Stability in Fractured Rock. Steinar Ottesen, ExxonMobil.

Numerous wellbore instability problems related to drilling through potentially fractured formations have been reported. Often, these rocks are characterized by the abundance of macro- and micro-scale bedding planes and/or networks of natural fractures. The presence of fractures weakens the rock mechanically and produces potentially higher permeability fluid flow paths within the low permeability rock matrix. Practically, it is difficult to identify fracture size and fracture density without a costly core sample.

This paper presents results from a geomechanical investigation of a wellbore instability incident experienced in a fractured shale formation. As part of this assessment, a preserved core was obtained from the fractured shale interval, and the presence of fractures was identified both by cat scan and visual inspection. A series of tri-axial tests were conducted to characterize the mechanical properties and failure strength of this shale.

This data, combined with wellbore stability modeling, suggests that the residual strength, rather than the peak failure strength, is a more representative measure of a fractured rock’s in-situ strength.

IADC/SPE 128712

Utilizing an Engineered Particle Drilling Fluid to Overcome Coal-Drilling Challenges. Sabine C Zeilinger, Fred E Dupriest, Ryan Turton, ExxonMobil; Hayden Butler, Hong Wang, Halliburton.

This paper describes a drilling fluid developed to stabilize coals in a program that was previously unable to achieve all extended-reach objectives. The fluid design principles are believed to apply broadly in stabilizing coals, fractured shale and other cleated formations. The rock mechanics that govern instability in coals is identical to shale.

However, coal instability often does not respond to the same remediation used in shale; and despite using an optimum mud weight, hole breakout or borehole collapse may still occur when the coal cleats and natural fractures of the coal allow the drilling fluid filtrate to invade.

The paper discusses the rock mechanics concepts, fluid design criteria for determining the allowed leakage rate when designing the bridging process, and the operational learnings from implementation. The use of the coal stabilization fluid and stability mud weight allowed the objectives to be achieved and contributed to record performance in this a narrow-margin drilling environment in Australia.

IADC/SPE 128913

Particle Size Distribution Improves Casing-While-Drilling Wellbore Strengthening Results. Rick D Watts, Mike R Greener, Stephen O McKeever, Paul Daniel Scott, David Hale Beardmore, ConocoPhillips.

This paper describes the application of particle size distribution principles for determining materials to be added to the mud system during casing-while-drilling operations. Casing while drilling has been demonstrated to stop or significantly reduce lost circulation and improve wellbore strength. The mechanism by which this improvement occurs is not understood; however, the results from this work significantly advance what is needed to get repeatable results.

If wellbore strengthening can be systematically achieved, then wells can be drilled in known loss areas without contingency strings of casing. In addition, wells drilled in mature fields where producing horizons have altered pressures, either from depletion or pressure maintenance, can be drilled, eliminating casing strings. Sidetracks become economical because hole size can be preserved for an effective completion, and well costs are lowered by not using additional liners to reach the objective.

IADC 127560

Clay-Free Synthetic-Based Fluid Provides High-Angle Wellbore Stability with Minimal Dilution and Treatment Requirements. Kalil Anthony Ackal, Arena Energy; Andrew Gillikin, Halliburton.

A seven-well development program in the Gulf of Mexico presented several drilling and logistical challenges to the Arena Offshore engineering staff. The high-angle 9 ^7/8-in. production intervals had shallow kick-off points. The complex well paths had proven difficult to drill with water-based fluids (WBF). Wellbore stability and torque-and-drag issues added to nonproductive time (NPT). Previous wells drilled with WBF experienced low penetration rates, multiple wiper trips and one lost directional bottomhole assembly. The decision was made to use a synthetic-based fluid (SBF) on the seven-well project, but deck space and pit-capacity constraints meant that the selected SBF would have to perform well with minimal dilution and product additions.

The use of the clay-free SBF allowed the operator to drill the wells considerably faster, at times drilling over 2,000 ft/day despite the high percentage of LGS.  No wellbore instability issues occurred, trips went smoothly and casing was run to bottom on every well.  Four of the seven original wells reached total depth at 21% below AFE cost, and several sidetracks were drilled for geologic reasons using the same clay-free system.

IADC/SPE 129090

Mesophase Spacer Designs Raise the Bar for Casing and Riser Cleanup in Deepwater Applications. Lirio Quintero, Chad Fulton Christian, Tom Jones, Baker Hughes.

A properly designed displacement spacer system should remove all foreign debris, completely water-wet all metal surfaces in a single pass of the spacer train and require no more than a single circulation of completion brine. The spacers should also be formulated to have superior detergency at cold seabed and downhole temperatures, prevent viscous emulsions or sludge, and be compatible with the drilling fluid to prevent channeling. Using efficient mesophase technology, a new spacer system has been developed and tested that does not require the use of common organic solvents or terpenes.

This novel two-spacer system has been successful in several deepwater applications, demonstrating its ability to efficiently clean the riser, casing and wellbore clean up tools. The displacement spacer system has been successfully applied during direct and indirect displacements of synthetic-based drilling fluids. This paper will discuss the challenges and successes of displacing synthetic-based mud in deepwater applications and the lessons learned.

IADC/SPE 128859

Pressure Transmission in Gelled Drilling Fluids in Deepwater Environments. Cesar Negrao, Admilson Teixeira Franco, Gabriel Merhy Oliveira, Federal University of Technology Paranã; Andre Leibsohn Martins, Roni Abensur Gandelman, Leandro LourenC’o Vieira Rocha, Petrobras.

Deepwater drilling is normally associated with narrow operational windows where gains and losses are frequent. Drilling fluids are designed to gel when they are not submitted to sheer stress. This is necessary to prevent cuttings from settling during circulation stops.

The current work presents a compressible transient flow model of the restart of drilling fluid circulation in order to predict pressures at the borehole. The model comprises the conservation equations of mass and momentum, which are solved by the finite volume method. A constitutive equation is employed to model the time-dependent rheology of gel breaking. Case studies are conducted to evaluate the effect of fluid properties, well geometry and pumping pressure on the bottomhole pressures. Major effects on gains and losses in deepwater drilling are highlighted.

Technical Session: Drilling Automation

IADC/SPE 126907

Closed-Loop Control for Decision-making Applications in Remote Operations. Jens Ingvald Ornas, National Oilwell Varco.

This paper describes how new technology and standards affect the way traditional control systems, used for operating drilling equipment, are prepared for interaction with drilling-by-wire systems or other systems that are capable of intervening directly in the drilling process.

Safe and reliable remote operation of drilling equipment will make it possible to reduce on-site manning, and thus reduce risk and cost involved in the drilling operation. Such systems will need a higher level of automation and will rely on a common computer-readable “understanding” of the drilling domain.

In order to achieve this, we need to find new methods to interact with both new and existing drilling control systems without going through complex, risky and long-winded integration phases.

AutoConRig is a RCN (Research Council of Norway-funded joint industrial project that addresses this challenge. It was started in 2008 and will continue until May 2012. AutoConRig is part of a larger project, Integrated Operations in the High North, which targets the implementation of a generation-2 digital infrastructural framework for integrated operations on the Norwegian Continental Shelf.

IADC/SPE 128234

The Automated Drilling Pilot on Statfjord C. Hans Freddy Larsen, Turid Eikebu Alfsen, Ronny Kvalsund, Statoil; Fionn Petter Iversen, Drilltronics Rig Systems; Morten Welmer, National Oilwell Varco; Oystein Hult, Trac-ID Systems; Sigbjorn Ekrene, Geoservices.

This paper is based on the experiences gained during the automated drilling pilot on Statfjord C. It provides new and valuable knowledge in three main areas: the performance of the new technologies in the field; the ability of the technologies to integrate through a standard industrial data interface; and the main technology enablers for the systems. This information gives an improved understanding of how these systems affect the drilling process in practice. Moreover, it is applicable for identifying the measures necessary in order to take full advantage of new automation technology in the drilling operation.

During the automated drilling pilot on Statfjord C, the field performance of the three systems were measured and evaluated to show how they influence a number of important areas such as HSE, operational efficiency, work tasks/responsibilities and demands on surrounding technology. In addition, the three system’s capability of exchanging data in real time to form a closely integrated automation system has been demonstrated and evaluated. Several crucial technology enablers have also been identified, the most important related to personnel training/experience building, drilling data quality/availability and the degree of offshore expert support.

IADC/SPE 128903

Automation of Well Construction Fluids Domain.Thomas Geehan, Mario Zamora, M-I SWACO.

The purpose of this paper is to define automation within the fluids domain aspect of different drilling and completion processes. The plan is to develop a technology road map to delineate the components in the processes and related functions. The well construction fluids domain includes, for the scope of this discussion, drilling, completion, waste streams and cement slurries. The domain interacts with many aspects of the drilling domain, from conventional drilling through well control to underbalanced drilling. The main discussion will be focused on drilling, completion and fluid streams for waste.

Over the last two decades, multiple projects have been initiated to better monitor critical fluid properties, control and/or automate primary solids control packages, including centrifuges, and mechanize with control chemical additions and mixing systems.

There has always been a serious disconnect in the well construction fluid processes in that the company responsible for delivering the optimum fluid properties in normal contracts does not own or has very limited input in the choice of the equipment used to fabricate and maintain the fluid. The integration of all the data logged on the well construction fluids normally reside with the operator and, as such, provide a look back on the history of the operation, not a method to control going forward.

IADC/SPE 128700

Fully Automatic Pipehandling Systems on a 6th-Generation Drilling Vessel. Kjell Rohde, Tore Berg, Thomas Yost, Svein Ove Aanesland, National Oilwell Varco; Gregers Kudsk, Maersk Drilling.

Drill-floor equipment controls and associated equipment on the latest-generation of floating drilling vessels have evolved into a system of computer-controlled machines that are currently operated by multiple operators, each running these machines from a series of dedicated control stations. The latest drilling vessels utilize as many as three operator stations per well center to drill the well, trip the tubulars or perform offline activities such as stand-building. These stations all individually control their respective machines but do require constant multi-tasking operations by their operators, which results in inefficiency and operator fatigue.

This paper will discuss the additional requirements of the control system and machine hardware and software and how the development process has taken this technology from concept to a working drilling system that adds value, efficiency and safety to what has previously been a multiple operator station control requirement.

IADC/SPE 127925

Drilling Automation – Novel Trajectory Control Algorithms for RSS. Justo Matheus, Siva Naganathan, Schlumberger.

Introduction of rotary steerable systems enabled faster and efficient wellbore delivery. This tested the limits of human operators to assimilate the MWD data, compare it and react with corrective actions to get back to the well plan. Rotary steerable systems are very sophisticated tools with downhole intelligence. This provides the framework to implement advanced and automatic downhole trajectory control algorithms that has no lag time and can perform consistent, accurate and reliable corrective actions.

This paper discusses the development and testing of next-generation, novel, non-linear trajectory  control algorithm that is able to hold inclination and azimuth downhole, run below mud motors and perform an automatic turn, while holding inclination with ability to control the gains while drilling ahead.

This paper also presents case studies of the runs from various locations worldwide that utilized this novel algorithm that helped to control inclination, azimuth, TVD within tight tolerance.

IADC/SPE 128286

Automation of Drawworks and Top Drive Management to Minimize Swab/Surge and Poor-Downhole-Condition Effects. Eric Cayeux, Benoit Daireaux, Erik Wolden Dvergsnes, International Research Institute of Stavanger.

Unwary axial and rotational movement of the drillstring can cause formation damage or fluid influx, resulting in costly remedial actions. With increasingly complex wellbore geometries and narrow geo-pressure windows, it is not always obvious for the driller to estimate the real maneuvering limits of the drawworks and the top drive, especially under poor downhole conditions. The solution presented in this paper addresses the continuously updated safeguards applied to the drilling control system to maintain downhole pressure within the acceptable pressure limits of the open-hole formations.

Since automatic actions can be triggered in case of an unexpected situation, some standard procedures have been fully automated, including friction tests and back-reaming. Numerical models are used to constantly calculate maximum accelerations and velocities, which can be applied to the drillstring in current drilling conditions. The resulting envelope of protection is depending on many factors, like the bit depth, the actual temperature gradient, the flow rate, the gel time, etc, but also the cuttings proportion or the presence of cuttings beds. Therefore, a proper evaluation of downhole conditions is of paramount importance for the quality of the calculated safeguards. An automatic calibration of the physical models, based on surface measurements, is at the heart of the system. The drillers involved in the testing of the system have found the system useful and user friendly.

The scope of use for such an automation of the drawworks and top drive goes beyond the continuous management of downhole conditions. Since the numerical models are calibrated under normal conditions, deterioration of the drilling conditions can easily be spotted. Such early warning of poor hole conditions gives the opportunity for the driller to take remedial actions before an incident has occurred.

Technical Session: Downhole Tools

IADC/SPE 128458

Asymmetric Vibration Damping Tool – Small-Scale Rig Testing and Full-Scale Rig Testing. Ian Forster, Alastair Henry Walter Macfarlane, Robert Dinnie, National Oilwell Varco.

This paper describes the work carried out at NOV Downhole on an in-house designed and built, small-scale vibration test rig that was developed with the purpose of understanding and quantifying the behavior of asymmetric vibration damping tools. The results are used to apply the technology to actual full-scale drilling applications and validate predictive modeling.

During field operations, the asymmetric stabilizer has been found to offer significant improvements in vibration levels during drilling; with resulting improvements in ROP and mechanical specific energy.

The scaled rig testing has demonstrated that asymmetry forces the BHA into first mode vibration motion and has the ability, supported by predictive software, to effectively dampen and suppress more harmful vibration modes (primarily backward and chaotic whirl).

Predictive software has been developed based on the scaled rig testing and may now be readily used by evaluation engineers in advance of and during field applications, and so aid the sizing, placement and operating parameters of asymmetric stabilizers. The software also gives indication of the predicted reduction in vibration levels.

Full-scale field operations where the vibration damping tool technology and use of predictive software has been applied have resulted in significant improvements in vibration levels during drilling. With reference to offset data, the paper presents actual field data that demonstrates significant benefits to slip stick, lateral vibration, ROP and MSE and the resultant beneficial impact on tool and bit life.

IADC/SPE 127738

Improvements in Multistage Fracturing of Horizontal Wells Using a Newly Introduced Single-Trip Coiled-Tubing-Conveyed Annular Perforating and Fracturing Tool – Benefits, Savings, and Case Histories. Rob S Hari, TriAxon Resources; Lyle E Laun, BJ Services.

Multi-stage fracturing of horizontal wells is quickly creating the same “step change” seen as when vertical wells first went horizontal. As new advances in drilling and completing horizontal wells are made, new solutions are needed to address the limitations of today’s multi-stage fracturing methods.

This paper will discuss the benefits, cost savings and case histories of a newly released single-trip, coiled-tubing-conveyed annular fracturing and perforating assembly.

IADC/SPE 127413

MWD Failure Rates Due to Drilling Dynamics. Hanno Reckmann, Pushkar Jogi, Franck Kpetehoto, Baker Hughes; Sridharan Chandrasekaran, TATA Consultancy Services; John Macpherson, Baker Hughes.

To analyze the effect of drilling dynamics on MWD tool failures, a unique database of MWD runs in challenging environments was created. This database includes vibration data recorded at 5-sec intervals from more than 12,000 drilling and reaming hours over a total footage of 425,000 ft. In addition to unique dynamics data such as weight, torque, bending moments and axial, lateral and tangential RMS and peak accelerations, the database included detailed run and failure reports, and environmental information such as well profiles and drilling operations.

The results of a statistical study using the logistic regression indicate the types of dynamic behavior most statistically significant in MWD/LWD tool failures. These are cumulative lateral vibration and backward whirl. Cumulative axial or tangential acceleration appears not to be significant in current MWD/LWD tool failures.

IADC/SPE 128211

High-Frequency Downhole Dynamic Measurements Provide Greater Understanding of Drillstring Vibration in Performance Motor Assemblies. Andrew David Craig, Rachel Sarah Goodship, David Robert Shearer, National Oilwell Varco.

The use of downhole mud motors to improve drilling performance in vertical wells is becoming more common through the oil and gas industry. The additional torque provided by a downhole mud motor allows for a more aggressive drill bit design to be selected and achieve a greater ROP. This paper will present a series of case studies where a near-bit dynamics recorder has been used to determine the dynamic conditions below a motor. In several cases, a dynamics recorder was also located above the motor, providing two discrete points of measurement.

Recently the oil and gas drilling industry has become increasingly interested in drillstring dynamics and vibration as a cause of drilling inefficiency and reduced drilling performance. Commonly, drillstring vibration is measured with shock sensors installed in MWD tools. While these tools provided valuable information on the dynamic conditions at the MWD tool, these tools are often fixed with regards to placement within the drillstring and are not designed to capture high-frequency dynamic data. As a result, the dynamic conditions at the drill bit are rarely measured, and the complete dynamic behaviour of motor assemblies is not fully understood.

Technical Session: Rigs, Equipment, and Smart Technology

IADC/SPE 128201

Evaluation of Precision Drilling Super Single Performance. Harold Gordon Griffin, Precision Drilling.

Drilling contractors strive to have drilling rigs that lead the industry in performance and safety. This paper will evaluate the Precision Drilling super single rig for the above operational metrics using hard data from wells drilled. The evolution of the Precision Drilling super single in all its configurations will be examined.

Precision Drilling keeps detailed history records of its own rigs, down to individual well data, and this internal data for super singles will be compared with industry data. Individual well cases will be examined where it is known that a conventional rig and super single completed similar wells in similar locations. Conclusions will be drawn for the super single on strengths and limitations.

The goal of this paper is to constructively review the operational history of the Precision Drilling super single to examine where it fits in today’s market and where it might fit in tomorrow’s market.

IADC/SPE 128953

Advanced Rig Technology – Future Technology Subcommittee Report of Activities and Industry Survey Results. Frank Benjamin Springett, Andy Dennis Shelton, National Oilwell Varco; Jeff A Swain, Chevron; Dustin Richard Torkay, Seawell Americas; Christopher Anthony Goetz, Kingston Systems; Thomas Geehan, M-I SWACO; Keith Allen Womer, KW Technology Services; Mike Killalea, IADC.

This paper is intended to report to the industry from the IADC Advanced Rig Technology Committee’s Future Technology Subcommittee a survey of the industry regarding needs for technological development and how they are valued. The paper will include survey results, as well as discuss ongoing committee work.

The group has produced three sets of deliverables to date. The paper will highlight learnings and assumptions when the group reviewed common factors that may or may not have contributed to the success of new technologies.

This paper will provide data and analysis along with conclusions that highlight methods and working groups in the industry. It shares some of the valuable results with recommendations for the industry to consider in the future development of technology.

IADC/ SPE 128285

Automation of Mud Pump Management: Application to Drilling Operations in the North Sea. Eric Cayeux, Benoit Daireaux, Erik Wolden Dvergsnes, International Research Institute of Stavanger.

Drilling in the North Sea is confronted with an ever-more challenging pressure management issue due to narrow geo-pressure windows in depleted reservoirs. Further, the occurrence of pack-offs can cause serious damage to the formation and contribute to nonproductive time. To address these problems, automation of mud pump management has been developed over the last four years to minimize the chance of fracturing the formation while starting the mud pumps or circulating. To account for abnormal flow restrictions in the annulus, automatic actions are also an integral part of the mud pump automation described in this paper.

Automation of mud pump steering can decrease the number of unexpected events related to high downhole pressures and therefore increase the overall performance of drilling operations. The project presented here has not only shown that the technology is viable but also that the end users are accepting the solution. The combination of the positive response of the drillers with the reduction of formation-fracturing events is justification for the additional investment in on-site instrumentation necessary to implement such a technology.

IADC/ SPE 128253

Continuous Motion Rig: A Step-Change in Drilling Equipment. Mads Grinrod, Well System Technology.

128253: “Continuous Motion Rig: A Step-Change in Drilling Equipment.”

For more than 100 years, tubulars have been run in and out of the borehole by setting the tubulars into slips on the drill floor and making up or breaking out the next tubular section. By the patent-pending concept of “continuous-motion rig,” no stop at the rig floor is required, allowing the drillstring, casing or tubing to be run with continuous speed into or out of the hole. The concept represents a step-change in drilling efficiency. Included in the presentation will be a six-minute animation that shows the concept and necessary equipment and their functions.

Technical Session: Hole Positioning

IADC/SPE 128899

The Developing Role of Deep Azimuthal Resistivity to Assist Optimal Well Placement in the Captain Field, UK North Sea. Chris Bell,Cecille Audinet, Lisa Hammond, Chevron; Ansgar Baule, Jonathon W Skillings, Melanie H Oxborough, Baker Hughes.

128899: “The Developing Role of Deep Azimuthal Resistivity to Assist Optimal Well Placement in the Captain Field, UK North Sea.”

The development of deep azimuthal resistivity LWD tools and their use in geosteering horizontal wells have become increasingly important in the development of the maturing Captain Field in the UK North Sea. We will discuss their development and why, as the field matures, in combination with a new strategy to access reserves, the role of the deep azimuthal resistivity has become a key service. We will cite particular examples where tangible benefits have resulted from its deployment.

Development and use of the deep azimuthal resistivity service and its use as part of an integrated service has already played an important role in the successful placement of recent Captain wells. It is anticipated that this role will become more important as the Captain Field matures, with opportunities becoming more challenging and in a very cost-conscious environment.

IADC/ SPE 128789

Bending Tool Face Measurement While Drilling Delivers New Directional Information, Improved Directional Control. Gerald Heisig, John Duncan Macpherson, Fadi Mounzer, Christian Linke, Mark Alan Jenkins, Baker Hughes.

From a differential geometry point of view, the course of a three-dimensional wellbore is fully described by its starting coordinates and direction, its curvature and its torsion. In directional drilling practice, the curvature is known as dogleg severity, which is assumed to be constant between survey stations when working with the minimum curvature method. Here, the torsion between survey stations is zero; however, discrete jumps in the well tool face (for example, referenced to gravity high side) occur at the survey stations.

This paper will present the theory of the bending tool face measurement, describe its implementation into a downhole MWD tool and show measurement examples from field applications. Furthermore, the paper will outline the use of the data for directional calculations. The paper will conclude with a discussion of applications in which the bending tool face information adds value such as reducing uncertainty in casing exit applications and improving directional control in challenging 3D well profiles. The discussion will be supported with field results.

IADC/ SPE 127753

Geomagnetic Referencing Service – A Viable Alternative for Accurate Wellbore Surveying. Benny Poedjono, Essam Eldin Adly, Mike Terpening, Schlumberger; Xiong Li, Fugro Gravity and Magnetic Services.

Wellbore positioning is a major challenge in eastern Canada because of the extensive faults in the Jeanne d’Arc basin. Accurate well placement is vital to the success of hydrocarbon production; accurate surveys are required in real time to drill 3D trajectories that penetrate multiple small geologic targets and avoid costly subsurface collisions with adjacent wellbores.

Magnetic surveying has become increasingly accurate and now provides a cost-effective alternative to gyroscopic surveys in real-time drilling applications.

Geomagnetic referencing can produce significant savings in overall project costs by providing accurate, real-time data on well position while corrections to trajectory are still possible. Geomagnetic referencing also eliminates the cost of extra rig time required to run a post-drilled gyroscopic survey, which can be a significant benefit where budget restraints are critical.

IADC/ SPE 128185

Improved Accuracy of Borehole Positioning in Horizontal Wells. Brett Lawrence, Apache Energy; Tanja Mojsin, Michael John Strachan, Halliburton.

TVD control and reduction in TVD error uncertainty has become an increasingly important element in field development and well placement. A field on the northwest shelf of Australia required precise positioning of the wellbore within the reservoir. The trajectory within the horizontal production section was completely dependant on accurate geometric measurements, keeping the well within 1 m of the target TVD for the length of the 1,600-m horizontal section. With great attention to detail, this is possible. However, the uncertainties associated with determining the actual wellbore inclination would normally overwhelm the required accuracy.

This paper outlines the methods used to reduce the TVD uncertainty whilst drilling long horizontal sections. Improvements were made to the standard ISCWSA MWD+SAG error model to simulate the increased level of accuracy generated as a result of the multiple sensor system. Using data from the two directional sensors and a continuous “at-bit” accelerometer assembly, the ellipse of uncertainty was estimated throughout the section and remained with a 1.5m (1sigma) limit. TVD uncertainty was set to zero at the gas/oil contact; total error from surface was not modeled.

Technical Session: Completion Technology and
Field Development

IADC/SPE 127447

Through Tubing Installation of Gravel Pack Completion Solves Long-Term Sanding Problem in Offshore Indonesia Well. Robert Allan Murphy, John Richard Overman, Lasmono Harjo, Weatherford International.

A major operator’s well in the offshore Northwest Java area in Indonesia was completed as a gas-lift installation, but it has had a lengthy history of severe sanding problems from each of four separate producing zones. A recent well test produced a rate of 135 BOPD. However, frequent sand clean-out jobs (four in the last five years) using coiled tubing (CT) with choke up strategy have been needed to maintain production. The well has low-rate marginal reserves, which cannot economically justify re-completion with conventional gravel pack techniques. In reviewing the alternatives available to permanently correct the problem, it was decided to install a gravel pack (GP) completion thru tubing using CT techniques.

In this paper, the authors will discuss the sanding problem and the various alternative solutions considered. They will go on to describe in detail the GP installation operation, the subsequent results where the objectives of sand-free production were successfully achieved and their implication for remediating other wells with similar problems.

IADC/ SPE 128302

Innovative Use of Plug and Abandonment Equipment for Enhanced Safety and Efficiency Corresponding Author’s Company: Weatherford. Delaney Olstad, Philip O’Connor, Weatherford International.

This paper examines the combination of aggressive engineering and competent staffing to solve P&A problems in a safe and efficient manner.

The paper presents four distinct jobs and the techniques applied to successfully complete the objectives of each. The paper continues with a discussion of lessons learned during the development processes; capabilities of the multiple systems; and the successful completion of each job with no recordable incidents, accidents or environmental impact. Cost reductions are correlated to the techniques and methods previously mentioned. Finally, the paper demonstrates the adaptability of the P&A equipment, techniques and resources that can be applied to other real-world applications.

IADC/ SPE 128481

Well Completion Applications for the Latest-Generation Low-Viscosity Sensitive Passive Inflow Control Device. Elmer Richard Peterson, Martin P Coronado, Luis Garcia, Gonzalo Alberto Garcia, Baker Hughes.

Passive inflow control device (PICD) performance in producer and injector wells under different fluid properties (density and viscosity) and operational conditions will be presented to show the technical benefits of this technique, as well as their improved recovery efficiencies compared with non-PICD completions. Fluid viscosity insensitivity of the PICD is critical to minimize preferential water flow whenever water breaks through into the well. The quantification of the benefits of this completion technique was performed using a fully integrated reservoir simulator where the PICD flow performance characteristic, well completion description (packers, blank pipe, gravel pack, annulus flow, etc) and reservoir simulation are considered.

This paper details the development of the latest-generation PICD design concept. Because these PICDs are permanent downhole components, their long-term reliability is imperative, and these new developments will improve their resistance to erosion and their ability to effectively balance inflow.  Finally, the field experiences and numerical simulation results are analyzed to establish the best well completion strategy to fit specific reservoir conditions.

IADC/ SPE 128191

Selecting Drilling Technologies and Methods for Tight Gas Sand Reservoirs. Nicolas Pilisi, Blade Energy; Yunan Wei, Stephen A. Holditch, Texas A&M University.

Compared with a conventional gas well, a tight-gas sand (TGS) reservoir will have a low productivity index and a small drainage area. The risk involved is much higher than the development of conventional gas resources, and the economics of developing most tight-gas reservoirs borders on the margin of profitability. Therefore, it is important to select the appropriate drilling method and technologies to drill a given TGS reservoir condition. However, we have found essentially no papers in petroleum literature that provide a logical method for selecting the best drilling method and technologies for given reservoir conditions. There are papers that discuss successful field cases where specific drilling methods and technology seem to work for specific reservoirs. We have used many of these SPE papers to help define “best practices” concerning the selection of drilling technologies and methods. We then developed logic to give advice to the user on the best drilling technologies and methods for specific reservoir conditions. In this paper, we will specifically cover the logic we have developed for choosing drilling technologies and methods for drilling a TGS reservoir.

IADC/ SPE 126675

Attic Thin Oil Columns Horizontal Wells Optimization Through Advance Application of ICDs and Well Placement Technologies in South China. Thanh Binh Tran, Y S Huang, J TigerLian, G Yu, Zhang Hua, Joko Yoseph Partono, Centers for Applied Competitive Technologies; Kim Fah Gordon Goh, Junn Shyong Lee, Jeffrey Chee Leong Kok, Yunlong Liu, Parlindungan Monris Halomoan, Schlumberger.

The horizontal well sidetrack campaign at CACT’s Huizhou Field in the South China Sea has been very successful and challenging over the last two years. Horizontal wells are well recognized in developing thin oil rim or thin layers within multi-stacked reservoirs by exposing the wellbore to maximum reservoir contact and drainage area. The lateral targets are attic thin oil columns in clean sands and remaining oil reserve in shaly sands. Since the oil column is thin at the top of clean sands with strong bottom water drive, early water breakthrough is observed even when the lateral is well placed on the top of the reservoir. Therefore optimum reserve recovery can not be achieved. CACT recognized that conventionally drilled horizontal wells with standalone screen sand control cannot guarantee optimum production performance.

The first ICD well has been producing at approximately 100% oil since early March 2009. Meanwhile, the second ICD well with well placement solution has just been completed, and production kick-off since early April has also shown approximately 100% oil production.

The mentioned integrated ICDs plus well placement solutions have shifted the conventional application of ICDs, which is hardware-orientated, from being dictated one way by hardware suppliers toward a holistic reservoir-centric design with an operation that keeps all parties informed and always in communication.

IADC/ SPE 128461

Successful Application of Dual Lateral Junction Technology to Develop a Marginal Gas Field in the Carboniferous Area of the UKCS Southern North Sea. Andrew John Hatch, Stuart Peter Rainer, Roger Simmonds, E.ON Ruhrgas.

This paper describes the application of dual lateral, level-4 junction technology to successfully develop a marginal field in the Carboniferous area of the Southern North Sea (SNS) on the United Kingdom Continental Shelf (UKCS). This is the first known use of this technology in this area of the SNS, where significant drilling risks have previously led to relatively simple well designs to mitigate the risk of failure.

The selected development scenario was a dual lateral well from a single subsea wellhead accessing both Rita main fault blocks. Although this concept yielded the most economic development scenario, it nevertheless gave the multidisciplinary team many significant well-design challenges.

Further, as the western fault block was largely unappraised, the well design had to accommodate the geological uncertainly of the NE-SW striking normal fault and the planned reservoir entry point being out of position.

Successfully dealing with these engineering challenges resulted in several industry firsts, which will be fully described within the text of the paper. On completion, production rates were as expected, with very good selective delivery from both legs prior to commingling.

Technical Session: Wellbore Issues

IADC/SPE 128720

Williston Basin– A History of Continuous Performance Improvements Drilling Through the “Bakken.” Alejandro Djurisic, Adrian Binnion, Anthony Thomas Taglieri, James Robert Thompson, Marathon; Mathias Menge, Curtis Fleischhacker, James Hood, Baker Hughes.

The Bakken formation was first discovered in 1951, but efforts to extract oil from it have historically been difficult. Efficient production of the Bakken has been achieved with long horizontal wells drilled through reservoirs at depths ranging from 8,000 ft to 10,500 ft TVD. The target reservoir depths and the extended lateral wellbore lengths require more powerful rigs to meet the operational demands of these well designs. The increased cost and tight economics associated with this play present a strong incentive to improve the drilling performance by reducing drilling time and cost. As a result, a strong focus was placed on improving drilling efficiency in the 9,000-ft to 10,000-ft lateral wellbore sections, which have the largest impact on the overall well cost.

This paper will introduce the challenges encountered when drilling these wellbore designs and outline the approach taken to optimize the drilling process. The use of high-performance drilling motors, a review of previously utilized BHA concepts, and the benefits of gathering additional real-time downhole drilling data to validate or change best practices will all be discussed. The data presented has been gathered over the past 18 months, mainly in Dunn County, N.D., and will show ROP improvements of about 50% over this time period. This improvement in drilling efficiencies has proven to reduce the overall drilling time and has impacted the economics of this play significantly.

IADC/ SPE 128941

Just How Reliable Is Your BOP Today? Results From a JIP, US GOM 2004-2006. Jeffry P Sattler, West Engineering Services; Frank B Gallander, Chevron.

In 2008, several industry groups created a task force to define the work scope for a joint industry project to study BOP reliability experienced for wells drilled in the US Gulf of Mexico in the 2004 to 2006 time frame. They also undertook to identify possible contractors, prepared, evaluated and awarded the bid for completion of this work scope, which included wells utilizing both subsea and surface BOPs.

This paper summarizes major findings and recommendations from the study. The study was easily the most comprehensive one ever completed, with almost 90,000 individual component tests analyzed in the course of drilling 238 wells using 37 different floating drilling units.

IADC/ SPE 128276

Behavior and Shape of Gas Kicks in Wellbores. Hermann F Spoerker, OMV Exploration/Production; Thomas Tuschl, Mining University of Leoben.

What does a gas kick look like once it has entered the wellbore and been mixed with the flowing drilling mud? Conventional assumptions of one “dry gas bubble” over a wellbore length equivalent to the total influx volume are clearly unrealistic. However, modelling the system of gas entering from a porous medium into an annulus with (in most cases turbulent) flowing drilling mud is highly complex and computer power-intensive.

The paper analyzes the driving mechanisms behind the gas influx and presents the results of a numeric model to simulate the behaviour of the gas volume in the annulus after the well has been shut in. It is part of a multi-year research project aimed at analyzing the wellbore gas influx system in more detail and allowing a better understanding of the behaviour of high-strength steel drill pipe in potentially sour environments. As the buffer reaction between the sour gas influx and the (generally) caustic drilling mud is heavily influenced by the initial distribution of the gas into the mud, the generation of bubbles (i.e., active surfaces) and the kinetic energy transferred to the system during the mixing process, the results of this study form the basis for subsequent high-definition simulators.

IADC/ SPE 128965

Case Study: Downhole Testing Tools for Formation Evaluation in High-Pressure and High-Temperature Environments. Thiago De Almeida Pontes, Halliburton.

The industry’s new direction into high-pressure, high-temperature (HPHT) reservoirs requires new technological methods for testing of these environments. In Brazil’s ultra-deep wells, the projects now include formation evaluation jobs in extremely HPHT wells.

The discussion will provide information for testing in extreme environments, which gauges are appropriate for specific conditions, and how to provide real-time data acquisition by adapting special procedures when temperatures will reach ultra-high temperatures not supported by available real-time gauges. The examples used will show the successes gained using these methods to perform DST operations in the ultra-HPHT reservoirs in Brazil.

IADC/ SPE 128933

Multi-Well Thermal Interaction: Predicting Wellbore and Formation Temperatures for Closely Spaced Wells. Albert R McSpadden, Oliver D Coker, Altus Well Experts.

A systematic simulation method is presented to predict wellbore and formation temperatures for a template of closely spaced wells. Multi-well thermal interaction will alter the wellbore temperatures as well as formation temperatures in the inter-well zones and further out from the well template. The change in temperature profile relative to a single well analyzed in isolation can be significant. For producing wells in close proximity, wellbore and formation temperatures can converge to a significantly hotter condition than in the isolated single-well case. The simulation technique employs standard industry thermal hydraulic modeling software and a finite element model in a loosely coupled, iterative analysis.

The modeling and simulation of wellbore and formation temperatures in proximity to closely spaced wells has not been widely examined to date. The problem has only been approached using theoretical formulations based on simplified assumptions. The current work presents for the first time a methodology based on standard industry tools and models that yield results consistent with field data. Results are presented for a case study example for a typical offshore HPHT field development.

IADC/ SPE 128249

Characterization of Sampling While Drilling Operations. Steven Villareal, Julian John Pop, Francois Bernard, Kent Harms, Albert Hoefel, Akira Kamiya, Peter Swinburne, Sylvain Ramshaw, Schlumberger.

The next step in the progression of reservoir-related services to the drill pipe is clearly the acquisition of formation fluid samples while drilling.

The first part of the paper describes a sampling-while-drilling tool that is comprised of a probe module; a pumpout module, which has contained within it fluid-property sensors, including a resistivity cell and a 10-channel optical spectrometer; a multi-sample module; and a power-generation module, consisting of a dedicated mud turbine and alternator, which provides power to the sampling tool.

The second part of the paper is devoted to the description and analysis of a series of tests that were performed to characterize sampling-while-drilling operations.

A systematic study of the variables and conditions that affect the quality of formation fluid samples acquired during while drilling operations and a direct, quantitative comparison with standard wireline sampling procedures will be presented.

Technical Session: Directional Drilling

IADC/ SPE 128767

Decoupling Stick/Slip and Whirl to Achieve Breakthrough in Drilling Performance. Xianping Wu, Luis Carlos Paez, Uyen Tran Partin, Mukul Agnihotri, Smith Technologies.

Stick-slip and whirl are the devastating vibrations that significantly limit drilling performance. They not only cause equipment failures but also increase nonproductive time, driving up field development costs. Although the industry has achieved tremendous improvements in fighting these dysfunctions, the root causes of stick-slip and whirl are still not fully understood.

New research strongly suggests that the problem is related to the drillstring’s tendency to couple stick-slip and whirl. This coupling is induced by improper bit selection and unfavorable bit/BHA interactions. For a given bit and rock, the critical values of WOB and RPM triggering stick-slip and whirl can be predetermined, assuming other drilling conditions are known and fixed. Plotted in a rectangular coordinate with abscissa of RPM and ordinate of WOB, these critical values represent the boundaries of stable drilling parameters.

The authors will present several case studies to illustrate the concept of optimum zone and its effectiveness on decoupling stick-slip and whirl to increase overall drilling performance.

IADC/ SPE 128243

Case Study – Field Implementation of Automated Torque and Drag Monitoring for Maari Field Development. Michael Niedermayr, Jack Pearse, Melanie Banks, OMV New Zealand; Gerhard Thonhauser, Philipp Zoellner, TDE Thonhauser Data Engineering.

This case study presents a novel approach to capturing torque-and-drag trends in real time while drilling complex and extended-reach wells. Data processing algorithms automatically process rig sensor data. They recognize current rig operations and log drillstring torque-and-drag parameters. Data are automatically collected, presented and shared without any exposure to human error or interpretation in data recording, allowing engineered real time and longer-term decisions to be made with accurate and consistent data. The tool relies on updated torque-and-drag models but otherwise works without further input or drilling process interruptions, and it does not require extra personnel on- or off-site.

The case study outlines technical difficulties encountered and how these were addressed during product testing and its first commercial field application.

IADC/ SPE 128915

An Experimental Study to Define Operational Parameters Governing Hole Enlargement While Drilling Offshore Heavy Oil Reservoirs. Francileide Gomes Costa, Marcus V.D. Ferreira, Elisabete Ferreira Campos, Fabiane Macedo, Atila Fernando Lima Aragão, Andre Leibsohn Martins, Petrobras.

This article presents a comprehensive data analysis of caliper logs in 11 offshore heavy-oil wells drilled in Brazil. The analysis correlates hole enlargement with relevant parameters such as fluid type, flow regime and BHA composition. Data sources considered were real-time monitoring equipment, logging data and drilling reports. Results indicate that water-based fluids, turbulence and certain BHA composition proved to stimulate hole enlargement and should be avoided.

The study is also supported by a unique experimental work where fluid flow conditions were simulated in a pilot unit where the wellbore was represented by a non-consolidated synthetic core saturated with high viscosity oil. For a given flow rate, hole enlargement is monitored with time by a real-time CT scanning technique. Experimental results are in agreement with field observations. The role of drillstring composition was not contemplated in the experimental study. Finally, a set of guidelines for design and operational procedures adopted for future drilling projects is presented. The results can be valuable for application in other regions with similar characteristics.

IADC/ SPE 128951

Truly Selective Underreaming: Adaptation of a Field-Proven, Hydraulically Actuated, Concentric Underreamer Allows for Multiple Locking/Unlocking Cycles in a Single Run. John Patrick McCarthy, National Oilwell Varco; William Martin, Petrohawk Energy.

This paper introduces a concentric underreamer that incorporates a drop ball mechanism that allows the operator to unlock and lock the tool multiple times without tripping from the well. The design concepts and processes, in addition to the field trials, will be presented and reviewed. Along with describing the new technology, significant gains in efficiency and cost savings will be quantified.

Concentric under-reaming tools have been rapidly developed along with the industrywide acceptance of closed-loop rotary steerable systems.

By adapting an established, field-proven tool, the primary challenges involved the cycling mechanism itself. This allowed for more rapid introduction to the industry as the risk to the operator was significantly reduced compared with running a completely new tool.

The result was a fully selectable, concentric under-reamer that was reliable and robust, yet offered the flexibility to under-ream selectively, lock the tool at the end of the run, and cycle the tool if necessary during the trip out of the hole.

IADC/SPE 128520

Real-Time Well Tool Face Information Reduces Directional Uncertainty and Risk in Difficult Sidetracks in Gulf of Suez. Tom B Howes, Mohammed Farouk, Mohamed Darwish, Gulf of Suez Petroleum Company; Wilhelm Koroletz, Ahmed M Ismail, Amin Moustafa, Gerald Heisig, Baker Hughes.

The development program of a field in the Gulf of Suez recently called for some difficult sidetracks out of existing 7-in. liners.

The paper will start with a detailed description of the directional challenges in this application. It will then introduce the concept of the bending-moment measurements and the derived directional information, well tool face and dogleg severity. After a description of the implementation and directional execution of the sidetracks, the paper will conclude with a discussion of the benefits and potential of this new directional-ontrol method, which could result in a reduction or even elimination of gyro runs during similar casing exits, thus saving significant rig time.

IADC/SPE 128329

Proven Methods and Techniques to Reduce Torque and Drag in the Preplanning and Drilling Execution of Oil and Gas Wells. Steve Renne, Juergen Maehs, Baker Hughes; Brian Lee Logan, Apache Corp; Nerwing Jose Diaz, Texas A&M University.

From 2007 to 2009, Apache Corp drilled several wells in the Gulf of Mexico in which the predicted surface torque from the pre-well planning phase was higher than top-drive limitations and/or drill pipe specifications.

This paper describes the torque-and-drag reduction methods that were found to be effective when fully applied over a series of wells. The torque-and-drag reduction methods were confirmed and proven through the analysis of field data and the use of modeling software. A case study of a 26,000-ft, complex S-shaped well is presented in this paper to illustrate those proven techniques.

Hoffmark is IADC regional VP – Europe

Jens Hoffmark

Jens Hoffmark has joined IADC as regional vice president – Europe. He is responsible for overseeing IADC operations and activities across Europe, including regulatory affairs and involvement with activities such as the European Operations Forum and the Offshore Competency Training Programme.

Mr Hoffmark retired from Maersk Drilling in late 2009, where his most recent assignment was vice president – business development. During a career that spanned 42 years, Mr Hoffmark’s experience with Maersk included a number of international assignments in various management capacities.

A Danish citizen, Mr Hoffmark will be based in Denmark and supported from IADC’s European Regional Office in the Netherlands. He can be reached at +45-4390-2888 or jens.hoffmark@iadc.org.

Technology Value Guide draft is online

The IADC Advanced Rig Technology Committee’s Technology Value Guide seeks to compare the pros and cons of emerging and existing technologies, as well as definitions, photos and training sources. A draft is available through the “ART Deliverables & Additional Resources” link on the ART Committee website on www.iadc.org.

Robert Urbanowski, vice chairman of the ART Reliability & Guidelines Subcommittee, encourages IADC members to contribute photographs, definitions and training resources. “We want the Technology Value Guide to be broad-based and represent as many companies as possible,” he said.

The guide is a matrix, with technologies or equipment as the column headers,  and row headers are “positives” and “negatives.”

UBO & MPD Committee elects officers

Companies interested in these important technologies are encouraged to participate on the committee. Complete information, including future meeting dates, meeting minutes and completed documents, can be found on the committee’s web page at www.iadc.org
/committees/ubo_mpd/index.html.

The IADC Underbalanced Operations & Managed Pressure Drilling Committee has elected officers for 2010. Brian Grayson, Weatherford International, succeeds Don Reitsma, At Balance Americas, as chairman. Inger Kjellevoll, Statoil, was elected vice chairman.

“We are grateful to Don for his service to the committee, and we look forward to continuing the work begun under his leadership,” Mr Grayson remarked.

The committee is presently drafting a “best practice” document for managed pressure drilling that is expected to be adopted by API as a Recommended Practice. It will complement API RP92U, which covers underbalanced operations.  In addition, the committee is developing an online screening tool that will help drillers select the most effective MPD technique for their wells.

The committee’s HSE & Training Subcommittee is also working on a new suite of training programs covering both UBO and MPD.

Northern Arabian Gulf Chapter picks leaders

The IADC Northern Arabian Gulf Chapter has elected its 2010 officers. Saud Otaibi, Saudi Aramco, was elected as the new chairman and Larry Connor, Precision Drilling, as vice chairman. Imad Al Enaizi, Al-Enaizi Enterprises, was re-elected treasurer and Ossama Z. Al-Mohtaseb, Rawabi Trading & Contracting Co, as secretary. IADC would like to thank the chapter’s outgoing chairman and vice chairman: Ali Al Ghamdi, Saudi Aramco, and Victor U. Ughelie, Arabian Drilling Co.

Well Servicing Committee launches survey

The IADC Well Servicing Committee has launched a survey of well control training needs and practices among well servicing/workover contractors that aims to assess the industry’s needs and desires regarding improving training for IADC’s well servicing membership, beginning with well control.

The Association of Energy Servicing Companies is assisting with the survey and plans to encourage its members to participate in the survey as well.

While the WellCAP program has a training curriculum for well servicing, workover/completion, wireline, coiled tubing and snubbing, the committee is interested in how widely used the program is, how it can be improved, and what obstacles to training might exist.

“I urge our well servicing members in the strongest possible terms to ask the appropriate person in your organization to complete this important, landmark survey,” remarked Mike Killalea, IADC group vice president/publisher. All information will be kept confidential, and data analysis will be done without regard to company identification. The survey can be found online at www.surveymonkey.com/s/SBY26Q2.

SAPC golf tournament set for 24-25 March

The IADC Southern Arabian Peninsula Chapter (SAPC) will hold its 2010 golf event on 24-25 March at the Emirates Golf Course in Dubai. More than 400 players are expected to participate in this premier golf event, each playing two championship courses over the two days. A networking gala event will follow the tournament.

For sponsorship inquiries and team slots, please contact Neil Howie at +971-50-4576177 or neil.howie
@petrostem.com).

By Jeremy Cresswell, contributing editor

Derek Mathieson

Derek Mathieson is president products and technology for Baker Hughes.

DC: The last two years have arguably been among the most extraordinary since the Great Depression, with the double whammy dealt by the credit crunch and violent oil price swings. Although recovery appears to be under way, what is your reading of the current situation and outlook for the oil and gas supply chain?

Mathieson: We believe that things are settling down again after the great upheaval. We think we’re past the inflection point in North America, but probably still in the trough on the international front.

Looking ahead to 2010, the consensus is that we should see a moderate recovery, particularly toward the second half of the year.

One thing we’re watching closely is the supply-demand gap, both for oil, where prices have been recovering, and on the gas side, where they have not.

Baker Hughes drilling fluid engineers in Kazakhstan use a mud balance to check the density of a drilling mud sample. The company says that its drilling and evaluation businesses were more stressed in ’09 while its completions and production sector held up.

The latter has completely changed, especially with the advent of shale gas in North America. And then there is the growth of LNG supplies and storage to consider.

We could see gas markets recover very quickly, but we’re dependent upon what happens in wider economic terms over the next several months and years. If we see industrial demand increasing and that supply-demand gap starting to close again, that’s when one could expect to see wilder swings in terms of prices and activity and vice-versa, therefore further scope for worry among the supply chain.

DC: You talk about shale gas in North America, where nonconventional gas has in effect become conventional. Do you think the same future possibility faces Europe, so upsetting the gas markets apple cart as we currently understand it?

Mathieson: I think that is becoming more and more likely. I don’t think anybody would have predicted five years ago that, with just one or two key technologies, the rate of change on the gas production front in continental North America would be so great.

The potential exists for that to happen in many other places around the world, and we’re seeing the first interest in Europe. However, there are shale gas reservoirs in many parts of the world, and I think it’s only a matter of time before today’s frontiers become tomorrow’s heartlands. I think we’re already seeing some of that transition in play.

DC: What are the biggest challenges facing the upstream side in the context of drilling/well construction, as the industry seeks to boost production in the face of shrinking oil resources, though possibly not yet natural gas?

Mathieson: Frontier areas really are becoming ever more challenging. In some environments, especially deepwater, we are reaching some of the fundamental limits of the standard materials used for drilling and completions.

In addition, risk mitigation is a critical concern and is now pushing boundaries in terms of how service companies and operators look at reliability assurance programs and try to figure out that whole transition from product development to commercial deployment.

As an example, it’s becoming increasingly difficult to plan out and work through a testing and deployment program where we go through de-risking the technology and proving it before it is qualified for use in these very hostile environments.

Continuing on the theme of risk, there’s more and more imbalance between technical risk, which is something we understand very well, and non-technical risks.

In many cases the non-technical risks are starting to outweigh technical risks in the frontier areas. Non-technical risk can be associated with regulatory or contractual concerns or geopolitical issues.

I think operating companies face real challenges in terms of mitigating such risk in some of the areas where we believe E&P activity is going to take place in the next five years or so.

DC: If you look at places where boundaries are really being pushed, such as subsalt (pre-salt) in Brazil, Angola and the US Gulf of Mexico, presumably bold companies like Petrobras, BP and Chevron will understand the technological challenges and that mistakes are going to be made?

Mathieson: These are very clear examples of where service and operating companies have to work together. For instance, Petrobras is encouraging service companies to come and build technology centers on-site at their research campus, CENPES, so we can work together through to commercialization of some of the technologies required for the next 20 years.

Subsalt is a great example. They (Petrobras) have realized that, in many cases, the industry doesn’t have the toolkit needed today to develop the fields that they’ve discovered. But Brazil is spurring some new and hopefully very fruitful relationships on how service and operating companies can work cooperatively on new technology to meet these challenges.

DC: Baker Hughes itself has been going through change, not least the acquisition of BJ Services, subject to approval. Can we home in on the different impacts of recent global events on the various business streams within the group?

Mathieson: It really has been an interesting year. In general, the completions and production sector has held up pretty well through the turmoil, while our drilling and evaluation businesses have been more stressed.

As the drilling rig count dropped off in North America, many of the product lines dependent on this activity were suddenly faced with overcapacity in the market, and prices went into free fall as a result. Wireline, drilling systems and drill bits were impacted most in the first half of 2009.

That really forced us to go back and look at our strategy in North America. Gone are the days of having a single strategy that works everywhere. Today it’s basin by basin for some businesses, with matching technologies and operations deployment strategies.

The shift has forced us to take a closer, granular look at how we’re organized around the world and to figure out the best ways to work with our customers as they confront their various challenges. And there’s an emerging and growing trend toward integration to contend with.

Many customers have been receptive to bundling or multiple product line bids, seeing this initially as a way to leverage spend. There is a spectrum of activity in this area all the way through to large turnkey projects, which some of the NOCs have favored recently.

I think the whole area of integration is something you’re going to see grow over the next couple of years.

DC: But industry goes in cycles. In a few years, surely the reverse could happen with contracts, and companies may organise themselves differently again?

Mathieson: To move with the trends, you have to stay close to your customers. In that regard, 2009 was a seminal year for Baker Hughes. In May we moved to a geo-market structure from essentially a divisional product line structure. That was a big step for a company that’s been organized one way for the best part of 100 years in some cases, such as Baker Oil Tools and Hughes Christensen.

The step to becoming Baker Hughes as one entity was a big one and was fundamentally driven by the need to get closer to the customer … to really understand market dynamics around the world.

We now have nine regional presidents who are responsible for sales and operations across all product lines. They’re positioned around the world so we have a much better view of the marketplace and have decision-making authority closer to our customers’ operations. This is helping us look at our customers’ challenges, not from a product standpoint but from a reservoir or solutions standpoint.

DC: Baker Hughes financials have taken a hit like pretty much everyone else, as evidenced by Q3 2009 numbers. The dramatic drop in profitability suggests that client oil companies are looking for better deals. Has that played any part on creating the new business model?

Mathieson: Reach back about 18 months; that’s when the executive team was looking at the new geo-market model. Our customers wanted one face. They didn’t want to have to deal with seven or eight individual product lines working on well and field development problems.

We were planning this reorganization during the up cycle, and during this down cycle we’ve had some time to settle the organization down, work through some of the integration challenges so we can enter the next cycle as a much stronger player.

As for the issue of clients looking for better deals, the operating community has been expressing concern for a number of years about the escalating cost of drilling and completing wells, especially in the frontier areas.

If you look at some of the elements behind that, a lot was driven by under-capacity at the time … not enough people, not enough equipment, so supply-demand was flipped the other way from where it is today.

We had to pay a lot of money to attract people into the industry. We had to put a lot of investment into building fleets (of equipment) for areas that were under-served. Essentially that cycle was spinning one way where costs were escalating for our customers.

Market inflection points, and 2009 is clearly an example, are really a chance to level-set everything. Unfortunately a lot of pain comes with that as we are forced to resize or rethink our market presence. It is a reality check.

DC: Are the structure changes likely to have any significant impact on the group’s technology development program?

Mathieson: I had a look at this going back over the last two or three cycles to see if technology had been impacted. I was a bit surprised that the rate of commercialization has been more or less constant throughout.

It helps that many of the big programs are three to five years in length. So, if the trough in a cycle is only a year or 18 months, then it probably only affects the technology development cycle a little.

Technicians test drilling equipment at the Baker Hughes beta rig in Oklahoma. The test facility allows Baker Hughes to accelerate new technology development.

Our technology spend year by year since 2008 has been flat. We haven’t backed off any of the programs. If anything, we’ve used 2009 as a chance to take a look at all our projects and clarify which ones should be the most commercially sound over the next few years. As we’ve taken down barriers between the product lines, we’re finding fertile ground for solutions that combine many product lines that we’ll be putting more focus on as we move into 2010.

DC: When switching from a product-line-based business to a geo focus, an issue that a company can find itself confronting is the risk of introducing barriers of a different kind – ones that can hinder technology transfer?

Mathieson: One of the things we’ve tried to do with the new organization at Baker Hughes is create a management structure that facilitates that transfer and lateral learning process.

My group (Products & Technology) essentially owns the strategic marketing plan, which is the strategy and planning process for Baker Hughes. This group spans the product lines; so we don’t actually have barriers anymore from an organizational structure. The critical role that the product lines play is ensuring a common global approach in their area of expertise across all of the regions. We have to share best practices and learn from our mistakes.

We also created, at the time of the reorganization, an enterprise-wide reliability and quality function. This group is acting as the glue across all the regions in the area of product and service quality. They have introduced one quality management system for Baker Hughes and one organization facilitating all of the root-cause analyses in the field, supporting our continuous improvement program.

DC: What are the big technology challenges in your view?

Mathieson: Our near-term portfolio is really focused on a range of solutions in the MWD/LWD world. For me, that remains one of the most technologically active and rapidly growing parts of the sector. If you look back over the last few years, you can count many tens of new innovations that have emerged in this area. That space race isn’t over by any means, and success is pivotal to unlocking some of the biggest challenges for our customers going forward. Near-term, that’s where the razor focus needs to be.

Very close behind that is completions, and one of the really critical aspects is next-generation sand control.

If you look at a lot of the deepwater fields around the world, sand management in general still seems to be one of the biggest elements in the ever-more challenging wells that our customers face. We’re looking at pulling a range of things from the Baker Hughes portfolio together to deliver what we believe are game-changing ways of looking at a reservoir-driven sand management strategy with a number of new technologies in the mix.

I think that’s going to be a pretty exciting area over the next few years as we bring some of these technologies to commercialization. That brings me back to one of the earlier comments about conventional technology at its limits.

Look at deepwater and HPHT, where we and others are pushing the boundaries of the materials used, especially metals and elastomers.

I’m excited about the work we’re doing with nanotechnology. We are working with fundamentals here, designer molecules, to fundamentally change some of the toolbox we have to work with for next-generation products.

I really believe this is one of the research areas that’s going to unlock some of the tools – materials – that we require to build the solutions needed for tomorrow’s challenges. It may be a few years out, but I’m confident we are already gaining traction.

Derek Mathieson joined Baker Hughes in December 2008 from WellDynamics, where he most recently served as chief executive officer. He holds a Ph.D. in micro electro-mechanical systems from Heriot-Watt University in Edinburgh, Scotland.

Nabors’ Rig 607 is drilling for Saudi Aramco.

Here is the good news: 2010 is shaping up to be better than 2009. Here is the bad news: It will still be a tough year.

Jackup and land rig utilization numbers are coming off bottom but still relatively weak. The deepwater market, which has largely remained immune thus far, is starting to feel pressure from extra capacity as newbuilds are delivered. Even already-contracted units can be problematic if subletting from operator to operator becomes a trend.

On the technology side, emerging solutions like MPD and subsea completions continue to seek wider acceptance, while companies are contending with pressures, temperatures, water depths and well depths that would have been out of the question just a few years ago.

Then there are our rigs. Are we building them with the features that operators require now and in the coming decades? As the need for completion and production capabilities increase, how can drilling contractors satisfy those on top of drilling requirements? Advances have been made on equipment such as top drives, mud pumps and fluid systems, but more improvements are still needed.

And the one critical issue that is again looming large is people. As rigs go back to work (we hope), experienced talent will be scarce. John de Lange of BG Group realizes the importance of a skilled work force: “If something goes wrong in well engineering, we all stare at the small black hole beneath the rotary table.”

At the start of a new year that everyone hopes will turn out better than the last, DC has gathered 11 industry leaders to express their hopes, plans and concerns for 2010 and beyond. It’s not all good news, but when is it ever?

Louis A Raspino, Chairman
Pride International

Louis A Raspino was appointed chief executive officer and president of Pride International in June 2005 and previously served as its executive vice president and chief accounting officer from December 2003.

Prior to joining Pride, Mr Raspino had served as senior vice president finance and chief financial officer of GrantPrideco and vice president finance of Halliburton. Before that, he served as senior vice president and chief financial officer and member of the office of chairman of Louisiana Land & Exploration (LL&E), where he led the company’s merger into Burlington Resources to create the largest independent oil and gas company in the US at that time. His career at LL&E spanned 20 years.

He began his career with Ernst & Young, leaving in 1978 to joint LL&E. Mr Raspino holds a Master of Business Administration from Loyola University and a Bachelor of Science in accounting from the University of New Orleans.

Matt Ralls, Vice Chairman
Rowan Companies

Matt Ralls joined Rowan Companies in 2009 as president, chief executive officer and member of the board of directors. He most recently served as executive vice president and chief operating officer of GlobalSantaFe Corp, from June 2005 until the completion of its merger with Transocean in November 2007.

Prior to that he served as senior vice president and CFO of GlobalSantaFe. He joined Global Marine in 1997 as vice president and treasurer and was senior vice president, CFO and treasurer prior to the November 2001 merger that created GlobalSantaFe.

Mr Ralls previously held executive positions at two publicly traded oil and gas companies and various management positions in commercial banking. He received an undergraduate degree in mechanical engineering and a Masters in Business Administration degree from the University of Texas at Austin.

Beth Gordon, Secretary-Treasurer
Diamond Offshore Drilling

Beth Gordon is the controller of Diamond Offshore Drilling and has served in that capacity for the last nine years. She graduated magna cum laude with a Bachelor of Business Administration degree from the University of Houston and has been a CPA since 1982.

Steve Gangelhoff, Vice President - Offshore Division
Northern Offshore Drilling

A 30-plus year contract drilling veteran, Steven J Gangelhoff, senior vice president of Northern Offshore Drilling has a career spanning operations management and marketing. Prior to joining Northern Offshore, he served as VP of sales and contracts for deepwater and VP of business for GlobalSantaFe Corp until its merger with Transocean. He holds a Bachelor of Arts degree in journalism from the University of Minnesota and a Master of Science degree in public relations from Boston University.

Jeff Flaherty, Vice President – Land Division
Helmerich & Payne IDC

After working his way through college as a roughneck, Jeff Flaherty graduated from Louisiana Tech University in 1987 with a Bachelor of Science degree in petroleum engineering. He worked as an engineer and operations manager for Justiss Drilling Co from 1988 until 1995. He joined H&P in 1996 as a drilling engineer and was promoted to offshore drilling superintendent in 1997. In 1998, he was promoted to district manager of H&P’s Mid-Continent operations in Oklahoma City. In 2006, he was promoted to his current position of vice president, US land operations, responsible for H&P’s fleet of 209 land rigs operating domestically.

David Reid, Vice President – Drilling & Well Services Division
National Oilwell Varco

As vice president, E&P technology and business at NOV, David Reid is responsible for developing corporate business interaction with strategic E&P companies. Joining Varco International nearly two decades ago, he spent three years each in the UK Drilling Systems Service Business and the Product Line Management for Pipehandling Products. He then spent another three years as director of marketing and sales with the Shaffer division of Varco before he became vice president of marketing and business development for Varco.

Dr Lee Hunt,
IADC President

Dr Lee Hunt serves as the chief executive of IADC, responsible for managing IADC’s worldwide operations. Before being named president in 1990, his prior association positions included manager for state government affairs, environmental affairs and human resources. Dr Hunt holds a PhD in political science from Northwestern University and received his law degree from South Texas College of Law.

Brian Petty,
IADC Senior Vice President,
Government Affairs

Brian Petty is based in Washington, DC, with global responsibilities for directing IADC’s government affairs initiatives. He serves as chairman of the federal Industry Trade Advisory Committee on Automotive Equipment and Capital Goods, which counsels the US Trade Representative and the US Secretary of Commerce on international trade issues. He also serves on their joint Investment Working Group to advise them on international investment policy. He co-chairs the Energy Services Coalition, comprised of 60 companies and trade associations seeking liberalization of trade in the hydrocarbon, electric power and renewable energy sectors at the World Trade Organization in Geneva, Switzerland. Mr Petty holds a law degree from Georgetown University and a master’s degree in literature from the University of Virginia.

By Jerry Greenberg, contributing editor

Siegfried Meissner

Siegfried (Siggi) Meissner is president of Nabors International Management.

DC: What are the critical issues the contract drilling industry is facing, and how is Nabors meeting those challenges?

Meissner: The challenge, first of all, is to keep your rigs employed. The market is very competitive, and the challenge is to be better than your competition.

DC: How good a job is the industry doing in keeping rigs employed?

Meissner: What we see internationally is the oil price has been steady in the high $70s and $80s, and I think the confidence is coming back in the international markets. We have a lot more bidding activity. We think we have bottomed out on the land rigs, and things are looking up.

In Saudi Arabia, where Nabors is active, the company employs Saudi nationals as rig managers who are “well respected,” said Nabors International Management president Siggi Meissner. Above, the company’s Rig 607 drills for Saudi Aramco.

The offshore market, because of the higher price of the jackups, is still more impacted. It will come back slower than the land rigs. It is mainly driven by oil, but international markets also have an additional driver for the gas drilling. We see activity increases in both markets.

DC: What areas are you seeing increased activity or new activity?

Meissner: The hot spots that I see coming back in 2010 are Russia, Middle East, North Africa, Mexico, and I think Iraq is going to have a play. International projects can have lead times. You may have to build a rig, and it might take nine months before you see real activity, so it might be 2011. To mobilize a new rig can easily take six to nine months of mobilization time.

DC: Are you seeing any new construction activity that is aimed to begin in 2010?

Meissner: Not yet, plus there is idle equipment, so I think the first focus is to get the equipment back into employment. That is the number one priority. As a drilling contractor, one of our main businesses is to optimize and upgrade or remodel the rigs to make them customer-specific. We do that all the time. Also, it’s not always economic, but sometimes it’s better to build from scratch. It depends on the project and what is required.

From our perspective, all of the rigs that we put out are like new. They are high-performance rigs. You just can’t come with a rig that doesn’t have good-quality equipment. It has to meet requirements such as hydraulic horsepower, good controls, etc, to compete in the market. We can only compete on the basis that we have rigs that can go the extra mile.

DC: Are you developing any new equipment or new applications for existing equipment to get above the competition?

Meissner: The trick is how you package the rig and how you staff the rig. We have in house several concepts of how to make a rig more efficient.

The top drive is a big element. We have a software called Rockit that helps the directional driller optimize the orientation of the drilling tool and reduce nonproductive time. We have had great success saving money for the customer with this. We have automation on the rig, which is primarily a tool for safety, but also it provides consistent production.

The workers have PLC technology and touchscreens, so you have better controls than just using a brake handle. All of that together gives you a better rate of penetration. If you drill faster, you save for your customer.

DC: Have there been other requests from operators for new technologies or solutions to help them save money?

Meissner: The customer always has a target for the number of days to finish a well. We benchmark ourselves to beat that curve. In house, we have real-time reporting to benchmark. At any given time, I can see if we are ahead of the curve. If not, we can discuss how we can improve the process, we can talk to the customer so we can optimize the process in the field.

DC: Coiled-tubing rigs are used in Canada with good results. Do you see this equipment moving more internationally?

Nabors sees an increasing demand for coiled-tubing drilling units internationally for well re-entries and predicts growing opportunities for CT units in 2010 and 2011.

Meissner: We see an increasing demand for coiled-tubing for well re-entries, and we are looking at that market right now. We don’t have coiled-tubing rigs internationally presently, but there definitely are opportunities in 2010 and 2011. Coiled-tubing is on its way in for sure.

Most of Nabors’ coiled-tubing rigs are in Canada and the US, and we have tried a few in Mexico. Some places in the Middle East are doing re-entries, so we are obviously applying the knowledge that we have in Canada. You see a lot more coiled-tubing on the workover side. On the drilling side, directional drilling, we see increased demand.

DC: Staffing has always been a thorn in the side, no matter what cycle the industry is in. I assume that’s still the case. Is it difficult to find and hire qualified people?

Meissner: When you go back 15 years, all of the supervisors were from one country, maybe the US or Canada, and then we had national crews. When you go to an international rig today, you easily have six, seven or eight different nationalities working there. We place a lot of emphasis on working the national crews, so the content of expats is very small, sometimes only two to three people per rig, and the majority are nationals.

That requires extensive training. But it also puts the challenge onto the supervisors because, instead of having people who speak the same language and have the same cultural background, they have to deal with people from different countries, different food on the rig, etc. It creates a completely different environment. It’s a challenge for our supervisors. These are the kinds of things that make it very complex to have a good team.

DC: Have you had difficulties melding cultures on rigs?

Meissner: It takes a lot of time, and it takes coaching. We do this through training and awards with our people if the rig is working well. We started 10-12 years ago to focus on that. In Saudi Arabia, for example, we are very proud to have Saudi nationals as rig managers. They are very well respected. And it solves other issues for us. They know how to handle the rest of the crew, security issues are minimized, a lot of other things fall into place. We also maintain our own training center to train nationals in various places.

DC: Any other issues on the land rig side?

Meissner: I fully believe in communication. Today, every rig has satellite communications. That means we are totally connected so we can immediately help if anything is happening on the rig. We can transmit pictures through dial-in features, we can put the best technicians in contact to help the rigs. But because we are centralizing the whole rig business into someone’s office, that can burden our people on the rigs with a lot of extra administration. A lot more people wanting a lot more information. If you are not careful, you will see your rig managers, mechanics and electricians spending a lot of time on a computer. That is different than what we used to do 10-15 years ago.

That’s a concern I have. I fully promote and am in favor of the connectivity, but there is a balance.

By balance, I mean whatever new systems you apply that they are user friendly. The target is that you make life easier so you want to give the rig crew access to information and help. In return, we can access performance data that we can use for other projects. We can compare rigs, how they are performing with rigs in the Middle East. I think that is what the system is all about.

DC: For a long time, operators have turned to drilling contractors and service companies to develop new technologies, new applications to existing technologies. Are they looking more to the service companies these days?

Meissner: It varies by customer, but in general we are participating on the tender process, which is very specific what the customer wants. They want 1,500 horsepower, three pumps, and you comply with that. Where the technology comes in, what a company like Nabors does, is we add certain things to the rig where we say, in addition, Nabors can offer this, and make our offer more attractive. That’s where technology comes into play, offering technology that has not been requested in the tender itself.

DC: Something like that you would throw in free?

Meissner: We don’t like free, obviously, but sometimes it’s something you would throw in because you want the job. Maybe there is additional work to get. Normally you would ask for compensation, perhaps based on performance. If you promise to deliver something better, you can optimize operations and reduce costs.

DC: Has the nature of the business changed over the past few years?

Meissner: I think the only thing that has changed onshore when it comes to customers is, we have a different customer base today. Traditionally we work for state oil companies and independents. In the past two years we’ve seen integrated service projects. Some of the big service companies are coming to us asking for drilling rigs. The service companies have the contract, they provide project management and all their products, but most of them don’t have their own rigs. So they come to us.

The issue we have is that those contracts typically are performance-based contracts. Naturally, the drilling rig is supposed to come into their model as the low-cost drilling provider. That’s a model we don’t like, of course. From our viewpoint, the only way that we can survive these contracts is we commit to performance and get the earnings that we are looking for through performance. It’s a change. It could be a modified footage contract. It comes down to drilling in a shorter time than you anticipate, and that’s where you get the better economics. You optimize the drilling process.

DC: Are these contracts becoming more prevalent?

Meissner: There are quite a few of them. Some of the state oil companies, PEMEX is a good example, and even recently Saudi Aramco, are trying this model. We definitely have seen an increase in those kinds of activities.

At Nabors, we are actually working toward taking the lead in these projects so we are not subcontractors. In some areas we are confident that we can take the lead, we have the capacity to take the lead and become the project manager ourselves. We could hire our own rigs, and we have several in-house products that we could link into the project, and then we would hire the other services as needed.

Nabors’ platform rig Rig 804 is operating from Murphy’s Azurite floating drilling, production, storage and offloading (FDPSO) vessel off the coast of Congo.

DC: Let’s turn to the offshore segment. What are some of the issues and solutions in the international offshore drilling arena?

Meissner: We don’t consider ourselves a major player in the international jackup markets. We have jackups in the Middle East, Saudi Arabia and Qatar that we purchased and rebuilt because our customers came to us looking for rigs, and we provided them. Because of our relationship with our customers, we saw the opportunity and we got into the business, and it’s been a good business for us. We started with jackups in 1999. We bought some jackups, refurbished them, rebuilt them to a different style, applied new technology and put them back on the market.

DC: What about your platform rig business? Are there new opportunities in addition to fixed platforms or spars, TLPs or other production systems?

Meissner: We are the leader in the modular platform rig market, which we operate on a global basis. We have rigs in the Far East, India, Mexico and the US Gulf that can move rapidly and efficiently because of their design. In West Africa, we have a modular platform rig installed on a production tanker, and it has a moon pool. We put the rig on the deck of the tanker, and we drill and produce using the same vessel. It is another thing that we have developed together with the customer. It is the only one in the world. We are trying to keep an edge over the competition.

Above and Below: Mr Raspino speaks at the June 2009 opening of Pride’s Lescar, France, training center – a nearly 14,000-sq-ft facility and a 2 million euro investment to ensure that employees are well-prepared for complex drilling operations.

By Linda Hsieh, assistant managing editor

“That which does not kill us makes us stronger” is an old saying that Pride International president, CEO and director Louis Raspino takes to heart. For him, market slumps are actually opportunities to make his company stronger, operationally and financially. This downturn has been no exception.

For example, in June 2009, Pride opened a nearly 14,000-sq-ft training facility in Lescar, France, a 2 million euro investment, to ensure that employees are well-prepared for real-life drilling operations. Then in August, the company completed the spin-off of Seahawk Drilling, which owned its mat-supported jackup rigs in the Gulf of Mexico. This was the finishing touch to a transformation Pride has been undertaking to make itself an exclusively offshore drilling contractor focusing on premium plays such as deepwater.

“Strategically, it was hard to focus on being the best in class in worldwide deepwater operations while also having to manage a very different type of asset in the US Gulf of Mexico,” Mr Raspino explained. “We’ve now invested over $3 billion in deepwater growth, and the company has been totally redefined. The market is beginning to recognize that by giving us more of a deepwater valuation.”

The downturn has also been a great opportunity for the company to sharpen its focus on financial discipline – something Mr Raspino takes very seriously. Now, the focus is on having the right people in the right place and concentrating on performance excellence.

The Pride Rio de Janeiro is on term contract with Petrobras in Brazil – a key focus market for Pride, along with West Africa and the US Gulf of Mexico.

Equally critical in a down market is the industry’s focus on safety and the environment, he emphasized, which must not waver if the industry wants to continue delivering value and performance to customers. As IADC’s 2010 chairman, Mr Raspino said, he hopes to lead the association by enhancing contractors’ cooperation with operators so that both sectors can work toward a better HSE record – because “our safety and environmental statistics are also their safety and environmental statistics.”

In the beginning

Although Mr Raspino didn’t have any direct contact with the energy industry while he was growing up, he recalls that it was pretty hard to live in New Orleans in the 1960s and ’70s without getting at least some exposure to the oil business. “It was the primary industry other than tourism, so it was something you paid attention to,” he said.

“And it always seemed like an exciting business – its worldwide reach, its importance to the global economy and the local economy, the associated geopolitical issues, the technical challenges – it just seemed like an exciting place to be.”

He received his bachelors degree in accounting from the University of New Orleans in 1973. Upon earning a Masters of Business Administration degree from Loyola University, Mr Raspino went to work for Ernst & Ernst (now Ernst & Young), doing public accounting, auditing and consulting for companies from a variety of industries. His primary clients, however, were from the energy industry, which gave him his first direct exposure to the business and helped him better understand how this industry works and what its challenges were.

In 1978, as the oil boom pushed toward its peak, Mr Raspino went to work for Louisiana Land and Exploration Company (LL&E), kicking off a two-decade career there that lasted until the company’s merger with Burlington Resources in 1997. During those 20 years, he did “almost everything you can do on the finance side of the organization,” from financial analysis, purchases and acquisitions, and special projects, to becoming the assistant treasurer, treasurer and finally senior vice president of finance and administration, and chief financial officer.

In 1998, following LL&E’s merger into Burlington Resources, Mr Raspino opted to leave the E&P side of the business and cross over to the service sector. He first went to Halliburton as vice president of worldwide finance, then to Grant Prideco as senior vice president and CFO. The difference he found in the service companies, compared with E&P companies, was startling.

“It is so much more volatile on the service side. There’s a lot more focus on cost, service delivery, customer satisfaction and performance excellence,” he said. As a whole, he also found that the service sector still lagged behind oil and gas companies in terms of management discipline.

E&P companies had gradually matured into highly disciplined and highly structured companies after the shock of the 1980s bust, he explained. “But when I got to the service industry, I thought it still had a ways to go in making that same transition,” he said, adding that part of his jobs at Halliburton and Grant Prideco was to bring in new ways of thinking and to implement more sophisticated management practices.

In late 2003, Mr Raspino was offered a position as executive vice president and CFO at Pride International – yet he almost didn’t take the job because he feared the drilling contractor industry would be “too simple.”

What possible challenges could a drilling contractor offer, he thought? After all, don’t they just “turn to the right”?

“I’m not the type of person who can go to work everyday in a boring industry where nothing is risky or exciting or threatening and everything is easy. It’s just not how I’m wired.”

Fortunately, he did decide to join Pride, and it didn’t take long for Mr Raspino to realize just how far this industry is from being “too simple.”

“The levels of operating complexity, infrastructure complexity, financial complexity and technical complexity are extreme. The people issues you have to manage when employees live in one part of the world and work in a far different corner of that world; the supply and demand factors you have to deal with; the safety discipline that’s required … quite frankly, I was surprised to learn just how really complex the business is from all factors,” he said.

Redefinition

More than these industry complexities, other challenges were also brewing at Pride when Mr Raspino came aboard in December 2003.

Through various acquisitions and joint ventures over the years, the company had amassed an array of valuable assets – hundreds of land rigs, shallow-water rigs, mid-water rigs, deepwater rigs, a rig construction business, an E&P services company and even a “floating hotel,” or accommodation unit, in the North Sea. Yet what did the company want to do with these assets? And what kind of drilling contractor did it want to become?

“The company had grown very quickly. Its size had outgrown its capital and management structures and needed a lot of strategic thought,” Mr Raspino said. “We needed a team to define a strategy. To do that, we had to step back and look at what we had at Pride. We had to figure out where we wanted the company to go in the future.”

The best place to be, they determined, was offshore – especially in deepwater. “We saw that deepwater is still an emerging growth area in terms of the geology. The industry has only begun to explore, drill and develop its potential. We believe that deepwater is where there are the best opportunities for impact discoveries,” he said.

Once a strategy was established and they knew where they wanted to go, they had to figure out how to get there.

Being able to communicate with employees was critical when Pride decided on a strategic change to focus on the premium offshore market, particularly deepwater. You have to work “with a team that believes in you as a leader,” Mr Raspino said.

First for Mr Raspino, management had to get employees to buy in to the new strategy and work together to implement it. “A big part of doing something like this is working with a team that believes in you as a leader, that believes in where you’re going and wants to go where you want to go,” said Mr Raspino, who tackled the challenge with discipline and determination. Systems and processes were re-examined and reorganized, and any assets that didn’t fit into the new strategy were divested; the proceeds were then methodically reinvested in assets that did fit in with the new strategic direction.

In just a few years, all the land rigs and shallow-water jackups are gone, while successful deepwater operations that were already in place in Angola and Brazil have been kept and enhanced with partner buy-outs. The company now boasts a strong presence in Africa and Brazil – key markets – with approximately seven drillships/semisubmersibles operating there in deepwater, and another four mid-water semisubmersibles combined in both regions.

The company also has invested in four ultra-deepwater newbuild drillships, under construction at the Samsung shipyard in South Korea. The Deep Ocean Ascension, Deep Ocean Clarion, Deep Ocean Mendocino and Deep Ocean Molokai will be able to drill in water depths of 10,000 ft to 12,000 ft and drill wells up to 40,000 ft. All will be dynamically positioned.

Three already have long-term contracts in place (two with BP and one with Petrobras). Upon delivery in 2010 and 2011, at least two of them will be going to work in the thriving US Gulf of Mexico deepwater. “That means we’ll have a significant presence in all parts of the deepwater golden triangle, and they will be our key operating regions in the coming years,” Mr Raspino said.

He adds that Pride is also looking at emerging deepwater markets, including India and Mexico. “We have seven independent-leg jackups in our fleet, and we’re putting most of those rigs to work in areas that will give us contact with customers that could develop into further relationships in deepwater.”

The people problem – it’s still there!

When commodity prices and the economy crash as fast and severely as they did in late 2008 and 2009, it’s understandable for companies to come down hard on spending. But if you’re cutting back significantly on hiring and training in this downturn – and Mr Raspino suspects that many companies are – then “they do so at their own risk.”

“We know the market is going to turn up again… and when it does, we’re going to feel just as panicked as we did a couple of years ago because everybody will be a couple of years older and closer to retirement. We have to work through this downturn by continuing to develop people,” he cautioned. “The industry can’t always count on finding talent in somebody else’s workforce. There just aren’t enough people.”

Pride is certainly not cutting back significantly on investments in people, Mr Raspino said. The company’s been recruiting and training crews for its newbuild rigs for some time now. Key supervisory and crew members are already in the shipyard with the first drillships, while others are working on existing rigs for training and skills development, he said.

Another example is the new Lescar training center. That facility features seven permanent instructors, a full-size simulator, a collection of drilling equipment students can dissect and repair, and a rig on top of a 3,000-plus ft test well so students can practice rig-floor and well control operations.

Mr Raspino believes that training centers like this are critical as the industrywide personnel shortage forces companies to put relatively inexperienced employees to work. Training centers provide a controlled environment so employees can make mistakes and, more importantly, learn from those mistakes.

“You can’t teach people the pit-in-your-stomach feeling when you make a mistake. That’s what teaches you not to make the same mistake again,” Mr Raspino explained, adding that Pride has plans to build another training center in Brazil.

The Deep Ocean Ascension is one of Pride’s four newbuilds to be delivered in 2010-11. It is already contracted to BP for five years.

The company is also developing a dual-track leadership development program, which began three years ago as a result of the demand for trained people. The program includes a technical track for people who love working on rigs and on rotations, and there’s another track purely for business management development.

“This industry tends to almost exclusively take drilling talent and move them to operations management. While this has been successful in many respects, I don’t think the industry has done enough to bring professionals from other disciplines into business management, and that’s something we’re working on right now,” Mr Raspino said.

He continued: “The industry still faces what I consider to be a very long-term crisis when it comes to having talent to run the industry. We must develop many leaders who don’t exist today.”

It’s a tough business

Other than its people problems, the industry also has tough challenges ahead that will demand innovative technological solutions and disciplined management. One of the toughest, Mr Raspino believes, is the volatility of commodity prices.

Low prices are obviously a problem since it impacts operators’ profit margins and therefore demand for rigs. But high prices can also be problematic, he said.

“As energy prices go up, it tends to attract speculative investments into our industry. That creates additional capacity, which affects the laws of supply and demand, which must be worked through in a downturn as we’re doing now,” Mr Raspino explained.

High commodity prices also tend to overexcite companies into hypergrowth, such as when oil prices were $100/bbl or higher. “It’s important to remain financially disciplined even in the face of that type of euphoria, and that means not overcommitting yourself to growth even when you have the short-term ability to do so. You have to remember: In the long term, things change.”

What makes things even more difficult is the fact that there’s nothing we can do to rein in this volatility because it’s driven by so many complex factors. “Volatility is just something we have to live with as an energy business,” he said.

In the near-term future, Mr Raspino believes that, with weak capital markets, growth forecasts will be much more measured, which might at least keep volatility from reaching such extreme levels as was seen in 2008. Plus, “seeing how fast an energy cycle can go from the top to the bottom has once again awakened people to the risks in this business.”

Still, Mr Raspino is extremely optimistic about the industry’s near-term and long-term outlook, especially for those companies with a strong balance sheet. Appearing on CNBC’s “Power Lunch” program on 30 July 2009, he noted that while the global economy is still deep in recession, the oil industry has already “passed” the bottom.

“We have to work through this downturn by continuing to develop people,” Mr Raspino said. “The industry can’t always count on finding talent in somebody else’s workforce. There just aren’t enough people.”

For months now, crude oil prices have been nowhere near the bottoms of $30s or $40s, staying within the $70s range – a price many would agree is quite healthy. “I think we’re at a point now where customers are coming out of their cocoons, where everybody has been the last year. They’re looking around and seeing that the world still has numerous investment opportunities at $70 or $75 oil.”

The fact that oil is a depleting commodity base in a world of growing demand also doesn’t get lost on people, which helps support prices, he said.

Industry cooperation

In the future, Mr Raspino hopes that the industry can find better ways to work with its customers so that drilling contractors are seen as more than just an asset that turns to the right. Rather than operators hiring contractors just to make hole, operators and contractors should collaborate as partners in order to reduce the total cost of drilling.

This is where IADC can make a difference, he said.

For decades, the association has been a forum where contractors – land or offshore, big or small – can get together to exchange ideas and discuss developing trends, technologies and challenges. In recent years, IADC has stepped up its efforts to get oil and gas companies, including national oil companies and host governments, more involved in these discussions as well. Operator participation in IADC conferences/workshops, committees and accreditation projects has been on the rise, and Mr Raspino hopes to push that trend even further during his 2010 chairmanship.

Especially in the areas of safety and the environment, he believes IADC can help bring operators and contractors together. “Operators care, and they’re serious. We need to demonstrate as an industry that we also care and are serious,” he said. “I don’t care how good we become, it’s never enough and we’ll always want to improve. We’re going to be putting a lot of undivided attention to continuous improvement in safety.”

Mr Raspino and his wife, Cheryl, have been married for 36 years. They have two children – daughter Christine lives in New York City and works in media and fashion, and son Michael is an attorney in Houston.

World’s 1st rotary steerable liner-while-drilling system tested on Brage platform Statoil has successfully tested the world’s first rotary steerable liner-while-drilling system from its Brage platform in the Norwegian sector of the North Sea. The new technology was jointly developed by Statoil and Baker Hughes. The concept of a rotary steerable system that gives operators the ability to accurately drill and log 3D well profiles with a liner attached directly to the drillstring

The ComPlete multizone single-trip system achieved a five-zone completion in the Mahakam Delta offshore Indonesia.

is new. The system is designed to withstand high circulation rates and high torque loads while providing liner connect and disconnect capabilities. Following a second deployment in January at Statoil’s Statfjord Field, the new technology will be commercialized.

In conventional drilling operations, the drillstring must be pulled before running the casing or liner. Liner drilling systems eliminate the need to pull the drillstring to run casing, saving time and drilling costs by minimizing the risk of borehole collapse and reducing NPT. The addition of rotary steerable capabilities helps overcome the challenges of drilling in zones with lower pressure and unstable shale/coal layers and in formations with varying flow and pressure regimes. This breakthrough technology was tested extensively onshore before being run on Brage.
Shell deploys open-water wireline at record depth

Shell and Oceaneering International set an industry record in subsea well intervention by replacing a failed subsurface-controlled subsurface safety valve in the Gulf of Mexico using the open-water wireline technique at a water depth of 2,673 ft (815 m). This is a record for producing wells. Open-water wireline had previously been deployed only in shallower waters. “This achievement is much more than a short-term record-breaking success. It is a game changer. Over the last 10 years, this technology reduced both the costs and frequency of interventions in shallow water, and I am confident we will see the same in deepwater,” said Peter Sharpe, Shell executive vice president – wells.

Oceaneering’s subsea intervention lubricator system is designed to perform wireline-based subsea well interventions without a drilling rig or large multiservice vessel and workover riser.

Longest solid expandable tubular liner cementation sets world record

BJ Services recently set a world record for cementing the longest solid expandable tubular liner for an operator in the Gulf of Mexico. Separately, the company also completed the 25th application of its ComPlete multizone single-trip (MST) system with a successful five-zone completion on the Sisi-Nubi project in the Mahakam Delta offshore Indonesia.
In the GOM world record, the 6,935-ft (pre-expansion length) 7 5/8-in. liner was set and cemented with a shoe depth below 20,000 ft (6,000 m). BJ used a custom-made XtremeSet cement slurry system to isolate the deep wellbore section, which had bottomhole static temperatures of 368°F (187°C).
To seal the annulus, BJ formulated the slurry to remain fluid for more than 15 hours downhole, permitting the expansion of the liner. Cementing specialists conducted extensive laboratory testing and simulation modeling to determine the proper circulating temperature for the application and precise additive package.
The custom slurry formulation weighted 18.7 ppg (2.24 g/cc) against a mud weight of 17.9 ppg (2.14 g/cc). The system performed as designed, yielding good density control, minimal fluid loss and zero free water. After drill-out and a leak-off test to 19 ppg (2.28 g/cc) equivalent mud weight, the operator commenced drilling with no need for remedial operations.
In the Indonesia project, the completion for Total E&P Indonesia involved five high-rate water-pack operations using a 9 5/8-in. system. The MST system required 3.8 days of operating time, saving an estimated 12 days of rig time. The well represents the 15th such completion for the operator since 2007.
BJ received a patent in June 2009 for the MST system’s ability to reliably isolate and stimulate individual zones of a multizone well in one trip. After securing positive, independent isolation of each zone with dual-element isolation packers, the system permits a variety of stimulation and sand placement techniques with little restriction to zone lengths and distance between intervals.
Assemblies for all zones are made on surface, and the assembly is run into the wellbore in one trip. After the zones are isolated and treated, an upper production string is run, enabling selective or commingled production through the opening and closing of production sleeves. The operator could even complete some zones and return later to complete the remaining intervals of interest.

Baker Hughes runs 24-stage completion in Williston Basin

KCA DEUTAG Oman achieves 1 year without recordable injury KCA DEUTAG Oman reached a milestone in October 2009 when the company completed one year without a recordable injury for the first time in its 46-year history in Oman. With more than 800 employees of KCA DEUTAG and its subcontractors working on eight rigs and the base, this comprises more than 2.5 million manhours. The company believes this milestone shows its commitment to safety, supported by client Petroleum Development Oman (PDO).

Baker Hughes in late 2009 successfully ran a 24-stage completion in the Williston Basin for Whiting Petroleum Corp – among the largest number of stages ever run using a ball/sleeve method for isolation. The Baker Oil Tools FracPoint EX multistage fracturing system used on the Ogden 11-3H well allowed the single-trip isolation of 24 intervals with an 8,000-psi pressure rating, while achieving high frac rates through all the ball seats.

The Bakken Shale/Three Forks play in North Dakota has seen an increase in activity due to fracturing improvements using multistage open-hole packer and sleeve systems. Advances in completion product development are enabling Baker Hughes to develop increasingly more complex fracturing systems that can be deployed in one trip, reducing the steps required to successfully complete a well.

This job was the first 24-stage FracPoint EX system Baker Hughes has deployed globally.

Riserless mud recovery system used for 1st time in Gulf of Mexico

Statoil has become the first operator in the US Gulf of Mexico to adopt AGR’s riserless mud recovery (RMR) system, which reduces discharges to sea, on the Discoverer Americas drillship on the Krakatoa prospect.

The Krakatoa well, in 2,060 ft (620 m) water depth, is the first application of RMR in the GOM. “The RMR system allows us to circulate the mud, reducing the total mud consumption and discharges to sea to a quarter of the amount compared with conventional methods,” said Tore Grønås, Statoil superintendent for the Discoverer Americas.

Mud costs and its transportation costs were also significantly reduced.

“In addition, this technology allows us to push the drilling depth deeper for the shallow casing string, which again reduces the overall drilling time per well,” he said.

“Minimizing the number of casing strings down to the reservoir is crucial for the success, especially within deepwater drilling where you may run out of options. With RMR technology, we have the opportunity to reduce the required number of casing strings and thereby reduce the total well cost by several millions of US dollars,” Mr Grønås added.

Statoil currently has two drilling units in operation in the Gulf of Mexico. RMR technology has been successfully used by Statoil on the Norwegian Continental Shelf in 19 operations.

The RMR system has been qualified and field-proven to water depths of 5,000 ft (1,525 m). It is being tested and qualified to be used in even deeper waters. RMR technology is used prior to installing the drilling riser, which means at the start of the well.

Terry Scanlon, AGR senior vice president – Americas, commented, “This is exactly the kind of well opportunity we were looking for on our first well in the GOM – top-hole instability with shallow water flow and shallow gas flow concerns – to establish our game-changing technology and services capability on these difficult GOM wells. “

Statoil used the RMR system with a four-stage pump on their GOM Krakatoa well top-hole section and, as a result, managed to maintain top-hole stability, circulate through unconsolidated water flow and gas flow formations and managed to push the 22-in. casing setting depth significantly deeper than had been achieved previously on offset wells. The system was deployed over the side, thus not interfering with direct line rotary table/moonpool activities.

Cameron MARS installs world’s 1st deepwater scale squeeze

Chevron has completed its first deepwater scale squeeze treatment using Cameron’s MARS (multiple application re-injection system) on well LDN4 in the Lobito Tomboco field in Angola.

The MARS system can be described as “a USB port for wellheads” and has previously been used for BP and Total for deepwater subsea pumping and metering projects. The MARS system, previously used for chemical injection operations by Shell in North Sea, has been extended for deepwater scale squeeze operations up to 600 m, with plans for extending the technology to 1,500 m. Chevron will use this system on 13 specially modified wells within the same asset to maximize production through the life of the field. The total scope of supply from MARS-PS included the deployment and chemical handling interfaces in addition to the MARS hardware.