Operational experience, contingency planning fill gaps in deepwater cementing

By Joanne Liou, editorial coordinator

Ragheb Dajani of Hess Corp provided an operational perspective on using cement as a primary barrier in deepwater wells at the 2012 OTC on 30 April in Houston.

Two questions need to be asked when considering cement as a primary barrier in a deepwater well: 1) Will the job be successful? 2) What if it isn’t? The two considerations beg to question and validate the prospect of a successful cementing operation. Ragheb Dajani of Hess Corp shared an operational perspective on cementing during a keynote speech at the 2012 OTC on 30 April in Houston. “There is a definite increase in recognition and scrutiny on the profound effects cementing can have on operations – on safety, environment and public opinion,” he said, “but the gap is in installing the cement as the barrier downhole.”

On paper, a lot has been done to support cement designs; however, there is uncertainty in effectively executing the operation.

It is important to understand the risks of a cementing operation and to approach it from a perspective that realizes the consequences of failure, Mr Dajani explained. A key challenge is in the cementing design, and the first step is to determine whether cement can realistically provide a barrier. “We can’t always rely on cementing unless we have a high degree of confidence to execute it and to provide a barrier downhole,” he said. “As we go deeper and deeper into the reservoirs, we’re asking for a small volume of cement to travel four or five miles. Yes, we can do that, but there is a lot of work that needs to be done ahead of time in order to protect that cement slurry to reach 20,000 ft.”

A strong understanding of the wellbore environment and the effects of contaminants on the cement slurry are among considerations that need to be addressed ahead of time. “Do we have adequate compressive strength development? Do we need to wait for the cement for a longer period of time until the contaminant actually sets to have an isolation barrier off the cement?”

As the cement is loaded offshore, it travels through a chain of custody that calls for quality control and brings Mr Dajani to pose more questions. “Are we using the right pressure on the lines? Is there too much moisture?” Quality control is necessary for the cement to maintain its chemical properties and a successful end result, he said.

On the training side, young engineers may have the knowledge but still lack field experience. An understanding of best practices cannot replace experience. “There’s a disconnect between designing on paper and having the experience level to have confidence in executing it in the field,” Mr Dajani stated. The challenge can be met by providing them with additional time and field training offshore.

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Baker Hughes Declares Quarterly Dividend

HOUSTON, April 26, 2012 /PRNewswire/ -- Baker Hughes (NYSE: BHI) President and Chief Executive Officer Martin S. Craighead announced today that the Baker Hughes Board of Directors declared the regular quarterly cash dividend of $0.15 per share of common stock payable May 18, 2012, to holders of record on May 7, 2012.

Baker Hughes is a leading supplier of oilfield services, products, technology and systems to the worldwide oil and natural gas industry. The company's 58,000-plus employees today work in more than 80 countries helping customers find, evaluate, drill, produce, transport and process hydrocarbon resources. For more information on Baker Hughes' century-long history, visit www.bakerhughes.com.

SOURCE Baker Hughes

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Are we laggards in technology adoption?

By Mike Killalea, editor & publisher

We pride ourselves on innovation, but are actually laggards at technology adoption.

“The oil and gas industry tends to have a technology adoption cycle of roughly 30 years from concept to 50% market penetration,” remarked Dustin Torkay, Seadrill, IADC Advanced Rig Technology (ART) Committee vice chairman-Future Technology, adding that this is an eight-year process in the medical industry. Mr Torkay is the driving force behind our 12 June ART Workshop on technology adoption. The afternoon workshop will convene in Barcelona the day before IADC World Drilling 2012.

Tom Bates, Lime Rock Partners, an ART workshop panelist, agrees that the pace of technology adoption is “painfully slow.” Mr Bates should know. His long career prior to joining investment firm Lime Rock as a managing director began with Shell and includes leadership positions at Baker Hughes, Weatherford Enterra and Schlumberger.

“There is almost an order of magnitude difference from other industries,” he said. “It’s a bit of a conundrum, (because) overall, our industry is not risk averse.”

Stagnation Generation

One case in point is stagnation in directional MWD, which, according to sponsors of a new Drilling Engineering Association joint industry project (JIP), has not appreciably advanced in a generation.

Now, before MWD partisans rouse to churn out indignant emails championing their companies’ achievements, let me stress that MWD overall has seen many advances. But, according to the DEA JIP sponsors, the process for directional MWD has barely budged in 30 years.

“The perception is that it’s good enough, because we are able to get to the production target,” said Robert Estes, Baker Hughes, which, along with ConocoPhillips and Bench Tree Group, are current sponsors.

The need for more precise directional MWD is pressing, Mr Estes says. A next-generation MWD tool drilling a relief well could reduce time to intersection and enhance accuracy. For infill drilling amid a spider’s web of directional wells, avoiding collision through pinpoint placement might prevent a blowout. For steam-assisted gravity-drainage wells, more precision can maximize production by optimizing well placement.

The organizers are seeking another seven or so JIP participants, at about $30,000 each. (Click here for more on the JIP.)

Dragging Innovation

The question remains. Why does innovation drag? ART workshop participant Jan Brakel, manager for wells R&D with Shell, suspects that with activity booming, the status quo suits most. “Is there a need to innovate?” he asks, though he himself is a strong proponent of change.

He points out that, rig newbuilding notwithstanding, a plethora of ancient equipment still keeps turning to the right.

“In general, as a drilling industry we have a significant catch-up opportunity in terms of technology,” Mr Brakel said.

Business Units Limit Vision

Mr Bates suggests that innovation began to flag when major oil companies switched to the business unit model.

“Business units are great for giving objectives and giving senior manager accountability for results,” he said.

On the other hand, a business-unit leader’s focus on that narrow bottom line is hardly an incentive to try something new, expensive and with potentially large downside risk.

Independents harbor a more entrepreneurial spirit, Mr Bates noted.

“It wasn’t a supermajor that developed the Barnett, with 25 frac jobs and 15,000-ft laterals,” he pointed out.

A corollary of narrowed vision is a dearth of test sites, he added.

“One of the frustrating things for me,” Mr Bates said, “is the inability to get products in the field and tested. That is a real barrier to progress.”

Mr Bates urges industry to develop a cooperative means to test promising technologies without jeopardizing wells, thereby helping to move technology forward.

“At the end of the day, technology works.”

Mike Killalea can be reached via email at mike.killalea@iadc.org.

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The great migration to wet plays

Liquids-rich US shales shine as industry sweet spot

Nomac Drilling’s Rig 245 drills well Gribi 1-9-1 3H in Tuscarawas County, Ohio. Photo courtesy of Chesapeake Energy Corp

By Katie Mazerov, contributing editor

The paradigm has shifted. US land rigs that just two years ago were at work in prolific shale gas plays are on the move, delivering an oil and liquids boom that has yet to be fully quantified. Whatever trends are occurring globally, US shales are the big story for 2012, driven by new play discoveries, technology advances and favorable pricing. Drilling contractors are seeing steady and rising dayrates and high utilization as operators shift their focus from the dry gas basins and set their sights on liquids-rich regions, such as the Bakken, Eagle Ford and the Niobrara, along with emerging plays believed to hold huge reserves.

“There’s a boom going on,” said professor Jeremy Boak, director of the Center for Oil Shale Technology and Research and chair of the Oil Shale Committee’s Energy Minerals Division at the Colorado School of Mines. “There are three or four significant oil-producing plays in the US today and a huge amount of excitement, with companies moving rigs as fast as they can. While gas is much easier to get out of impermeable rock, the technology in multi-stage fracturing has advanced to the point that we can now produce oil and wet gas in these areas. In many regions, such as the Bakken, the best-producing horizons are in silty rocks, siltstones and dolomites that are interbedded in the shale.”

Since the industry cracked the shale oil code in the Bakken in 1999, production in the play has increased 55% per year, a phenomenal growth rate for a new resource, Dr Boak noted. “Potential for the Bakken is predicted to reach one million bbls per day by 2019, just 20 years after production started. It took the US 65 years to reach that number in conventional oil production and 40 years for the Canadian oil sands to achieve that.”

Meanwhile, there is a debate among some geologists over what to call the oil produced from shale. As the Bakken play developed, the industry called it shale oil, a term used since the early 1900s to refer to organic-rich shale that requires heating to produce oil. However, Dr Boak prefers to call shale containing liquid hydrocarbons “oil-bearing shale,” and the product, “shale-hosted oil.”

Big E Drilling’s Rig #1 operates for Rosseta Resources in the Eagle Ford.

Aside from increased production in the Eagle Ford and Niobrara plays, operators such as Chesapeake Energy are ramping up activity in the newer hot plays, including the Utica, underlying much of eastern Ohio, and the Mississippi Lime, or Mississippi Chat, spanning across northern Oklahoma and southern Kansas. The Tuscaloosa Marine play, a deep (10,000 to 15,000 ft) formation in central Louisiana and southwest Mississippi is believed to hold seven billion bbls of recoverable oil, an estimate made as far back as 1997, Dr Boak noted.

Despite concerns about hydrogen sulfide (sour gas) and high levels of produced water, particularly in the Tuscaloosa, there are no signs of a slowdown, he said. “Oil prices right now are high enough that an operator can spend a good deal of money going after the oil.”

Rates Steady and Rising

Nomac Drilling, an affiliate of Chesapeake Energy, has 113 marketable rigs with 110 active in the Eagle Ford, the Mid-Continent (including the Granite Wash, Cleveland, Tonkawa and Mississippi Lime), the Barnett, the Haynesville, the Bakken, the Marcellus and the Utica. In the Utica, Chesapeake plans to increase the rig count to 20 by year-end and to 30 by year-end 2014.

“Like most contractors, we are experiencing migration from dry gas plays to wet plays,” said Jay Minmier, Nomac president. “Fortunately, due to our relationship with Chesapeake, these changes do not impact Nomac’s utilization, only its deployments.”

Crews on Nomac Rig 245 work to drill well Gribi 1-9-1 3H in Tuscarawas County, Ohio.

Mr Minmier reports that rig rates have remained favorably steady since Q3 2011 and currently range from $18,500 in the Barnett to $29,750 in the Bakken. “Nomac’s rates are market-based so we aren’t immune to price fluctuations. We do believe that, to the extent wet plays can absorb the capacity leaving the dry plays, overall pricing will remain stable, although weakness is expected in certain areas like the Barnett and Haynesville.”

All of Nomac’s marketable rigs are either working or undergoing upgrades for upcoming jobs. “Our utilization has historically stayed between 95% and 100%, and we will be fully employed again once the upgrades are fielded,” Mr Minmier said. Twelve new rigs are slated for delivery through April 2013, with two 1,500-hp rigs for oil drilling in the Powder River, Wyo., region and 10 1,200-hp rigs for the Utica. Dual-fuel systems are being added to the majority of its fleet to allow the rigs to run on compressed natural gas or liquefied natural gas, as well as diesel.

“Many of our existing rigs and all our newbuilds have walking systems to facilitate efficient, slot-to-slot moves on a single pad,” Mr Minmier said. “Our newest rigs also include certain innovations to reduce location-to-location move times. We are focusing heavily on mobilization times as this portion of the well manufacturing process has become much more visible due to faster drilling times.”

From a technology perspective, the company has not been limited on lateral lengths. “To the extent that some laterals are shorter than preferred, it is almost always a leasing issue,” he added.

Nomac is implementing an accelerated development program for drillers, directional drillers and rig managers aimed at reducing the time required to train competent rig leaders by 60% over traditional methods, Mr Minmier noted. The program is targeted to young, motivated professionals with no industry experience.

Big E Drilling has shifted its fleet from the Haynesville to the Eagle Ford play, a move president and CEO Lyle Eastham said was justified given the current pricing environment. “We decided to go where the liquids are,” Mr Eastham said. “There could conservatively be 10 to 15 years of drilling in the Eagle Ford. When we moved into the play three years ago, there were only 30 rigs. Now there are nearly 240 operating.”

Today, the company’s five rigs are all operating in the Eagle Ford, including one the company built 18 months ago.

A Precision Drilling Super-Triple (ST) 1200 rig moves to the next well on a pad in the Marcellus play. The self-moving rig can move with a full setback of tubulars.

“We have added a lot of automation equipment, including top drives, catwalks, blowout preventer lifts and rig walking systems, to our rigs, which have enhanced safety and efficiency and aided in the contracts we’ve been awarded,” Mr Eastham continued. The fleet is designed for horizontal and directional drilling at depths from 15,000 to 25,000 ft, with dayrates in the mid-$20,000s.

But he also gives considerable credit to the company’s stable work force. “All our pushers have a minimum 20 years of experience, and we have a lot of 30-year employees with little turnover. We keep our rigs busy, and run a safe, efficient operation.”

Walking the Walk

Newbuild activity is also healthy in North America, with many of the major companies ramping up their fleets with efficient, highly mobile rigs suited for shale wells and pad drilling. Calgary-based Precision Drilling delivered 18 new rigs in 2011 and has contracts on 33 more to be delivered by the end of 2012 in North America.

“These are state-of-the-art, tier one rigs that are equipped with pipe-handling systems and integrated top drives, and all run range three (45-ft) tubulars. They are designed with a small footprint in mind,” said Doug Evasiuk, senior vice president of sales and marketing, North America for Precision.

“Pad drilling continues to be attractive to operators wanting to minimize the environmental footprint, limit truck traffic and reduce move times,” he said. “All the major companies are building rigs that have the capability to walk from wellbore to wellbore to eliminate trucks. With our Canadian roots, we understand how to do that, especially for cold-weather environments. All our rigs going forward will have walking systems or the capability to accommodate them.”

Precision’s newbuilds for the US market include seven 1,200-hp rigs and 17 1,500-hp models. All are AC Super Triple rigs. For Canada, where wells are generally shallower, the bulk of the rigs are the Precision Super Single design. The Super Single rigs also run range three tubulars and have fully automated pipe-handling systems.

Nabors Drilling USA Rig 681 (above) and Rig B4 (left) are both working in the Bakken Shale of North Dakota. Rig 681 is under contract to XTO Energy while Rig B4 is working for Hess.

“In Canada, because we have a compressed drilling season and have to be very efficient, we’ve always been focused on highly mobile rigs,” Mr Evasiuk continued. “Over the years, technology has enabled operators to drill considerably faster. Wells now are taking far less time than they did in the past, meaning we’re moving a lot more than we once did. When we’re moving, we’re not drilling the well, and that translates to nonproductive time, which is costly for our customers.”

Dayrates have been solid, particularly in the liquid plays. Precision began shifting from the dry gas plays to the liquids last year, a trend that will continue, Mr Evasiuk said. The company’s large presence in the Haynesville has shrunk from the peak level of 26 rigs to just three. “There has been enough activity in the liquids plays to absorb rigs coming out of the dry gas markets.”

Rig B4

US utilization is above the industry average. Of the company’s 150 US rigs, 104 are operating in all the major plays, including the Bakken, Eagle Ford, West Texas, Mississippi Lime and Tuscaloosa. Precision has yet to enter the Utica but has been approached by operators in that region.

As the largest drilling contractor in Canada, Precision has operations in every major basin, notably the Cardium, Viking, Duvernay, Canadian Bakken, oil sands and heavy oil. Utilization in February was around 85% but has recently declined due to the spring “break-up,” which occurs late in Q1 and can carry into Q2. The thawing makes transporting equipment difficult. Traditionally, 35% to 40% of drilling activity in Canada occurs in the winter months.

From a technology standpoint, Mr Evasiuk believes the push for longer laterals will be achieved by further development of completion designs. “The industry has the capability to go out a lot farther, but it really becomes an economic decision by the operator to determine what the length of the horizontal section should be.”

Outside North America, Precision has two rigs operating in Villahermosa, Mexico, and three in Saudi Arabia. All are 3,000-hp rigs for deeper wells.

Increasing Automation

Nabors Drilling has seen an uptick in US land rig utilization, primarily in the 1,000- to 1,500-hp size being deployed in most of the shale plays, said Denny Smith, director of corporate development. “Overall, US land rig utilization is around 80%, but utilization is virtually 100% for our rigs in the highest demand window.” He sees dayrates averaging in the mid-$20,000s.

Commodity pricing is the key driver for the shifting market, a trend that began back in 2010. The weak gas price phenomenon is isolated to North America.

Nabors initially shifted several rigs from the Haynesville to the Eagle Ford. Two years ago, 58 Nabors rigs were working in the Haynesville; today there are 26. Along with a significant presence in the Eagle Ford and the Permian Basin, the company has several rigs in the Mississippi Lime, with plans to move two more from the Haynesville. The company also plans to move one or two additional 1,500- to 2,000-hp rigs into the deep Tuscaloosa play to go after gas liquids and oil, Mr Smith said.

Nabors Drilling’s Rig 109 is working for XTO Energy in the Bakken Shale, where Nabors remains the largest drilling contractor.

Additionally, Nabors remains the biggest drilling contractor in the Bakken. By the end of 2012, the company will have 76 rigs, including several newbuilds, in the play.

“The market will continue to be this way for awhile. Gas continues to be oversupplied, in part because of the associated gas that is being produced with the liquids and oil,” he continued. “There is a broad range of pricing right now. I think there is a lot of latitude for prices to even moderate some and still keep a pretty robust market. Our customers have indicated they would continue drilling if oil prices get as low as $75 to $80 in the Bakken and $60 to $65 in the Permian.”

Mr Smith said shale production, particularly horizontal drilling, has benefitted from an increase in pad drilling and major advances in downhole logging and real-time technologies. “I think there is going to be a trend toward more automation and remote control of the drilling processes that will spark further improvement  in the next two to five years in rig efficiency, with increasing numbers of AC rigs featuring digital controls and automatic drillers.”

Through its wholly owned subsidiary, Canrig Drilling Technology, Nabors manufactures top drives and other rig systems and intelligent software technologies. At year-end 2011, the company had 119 AC rigs in the US, with 31 newbuilds planned this year. Most of the contracts are for the US market, but at least two have been designated for Canada and three for other markets. Outside the US, the market is recovering, with Nabors’ land rig count expected to increase from 116 at year-end 2011 to 130 by the end of 2012. The company saw peak activity during the seasonal Canadian market, with close to 50 rigs operating in the oil-rich Montney, Duvernay and Cardium plays, Saskatchewan, and the Horn River gas basin.

A lack of service infrastructure has led to low unconventional production in Australia. “If there is a rig operating, it will be for one well, and it will be extremely costly,” said Warrego Energy’s Dennis Donald. The company holds a permit for a block in the North Perth Basin, estimated to hold one of the world’s largest shale gas reserves.

There is more gas drilling in the Middle East, particularly Saudi Arabia. “We do the majority of the gas drilling in Saudi Arabia with very high-spec, 2,000-hp rigs with multiple blowout preventer stacks for the high-pressure wells,” Mr Smith said. Nabors also has 15 rigs in the Llanos Basin of Colombia and is drilling oil for two major operators in Russia.

An Anticipated Bonanza

But there is one area of the globe where drilling activity is at a near standstill. Despite favorable market conditions, a lack of service infrastructure is retarding progress.

Dayrates in Western Australia are at least 48% higher than US rates, despite gas prices that are $8-$10 (and rising) per gigajoule, considerably higher than North American prices, with acre lease costs of $500 or less, said Dennis Donald, a partner at Warrego Energy.

The company holds an unconditional permit to develop an 86-sq-mile block in the North Perth Basin, which is estimated to hold the fifth-largest reserve of shale gas in the world. The block contains the West Erregulla tight-gas field, which underlies the Kockatea shale play recently mapped by the US Energy Information Administration. The company plans to do seismic testing this year and begin drilling in early 2013.

Mr Donald cites lack of service infrastructure as the primary reason for the low unconventional production in the vast region, in part a function of the cannibalization of rigs being used for the vigorous coal seam gas activity in the eastern sector the country, thousands of miles away. “But with the government’s push for gas to replace diesel in Western Australia, operators have been given permission to utilize hydraulic fracturing to open up the gas shales,” Mr Donald said. “There eventually will come a tipping point, and when production does open up, this will be a massive market, and we will see a bonanza for rigs and fracturing.”

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People, Companies & Products

FMC to supply Petrobras with subsea equipment

FMC Technologies recently signed a four-year agreement with Petrobras for the supply of pre-salt subsea equipment.

FMC’s total scope of supply could include the delivery of up to 130 subsea trees, subsea multiplex controls and related tools and equipment.

The tree systems are for use offshore Brazil in water depths up to 8,200 ft (2,500 meters). The equipment will be engineered at FMC’s South American Technology Center and manufactured at the company’s subsea facility, both located in Rio de Janeiro.

The subsea trees will achieve 70% Brazilian local content, and deliveries are scheduled to commence in 2014.

Gazprom awards Expro three PVT contracts in Iraq

Expro has secured three contracts in Iraq. The trio of contract awards adds to a recent contract with Eni.

Expro will undertake analysis of more than 100 pressure, volume and temperature (PVT) studies in a contract award with Gazprom in the Badra field close to the Iranian border. Two further contract awards with large operators in the south of Iraq involve further PVT sampling studies and laboratory work.

Expro will utilize its Iraqi capabilities, as well as its fluids analysis center and analytical data services teams in the UK, to conduct more than 200 PVT studies.

Baker Hughes facility targets unconventional resources

The Baker Hughes Dhahran Research and Technology Center recently opened in Saudi Arabia with a focus on research and development of new technologies to unlock the potential of unconventional resources.

The technology and research center is a partnership between Baker Hughes and Saudi Aramco.

The center brings together the competencies of Baker Hughes engineers and scientists of Saudi Arabia and King Fahd University of Petroleum and Minerals to develop application-specific solutions. With rock and fluids laboratories, the center provides equipment to understand the science and technology in developing unconventional resources.

Transocean’s global training center in Macaé opens

Transocean’s training center has opened in Macaé, Brazil, in the city’s busiest industrial center. The facility provides the latest in technology and teachings. The company plans to install a cyber-based drilling simulator to train drillers who work on the latest-generations of offshore rigs.

Estimated demand this year is more than 200 classes for personnel from Brazil and other Transocean locations worldwide. For the first time in Brazil, Transocean personnel can take drilling and crane operations competency assessment classes, D-CAP and C-CAP, using simulators onshore, in addition to offshore assessments.

Murchison Drilling Schools expands in Houston

Murchison Drilling Schools (MDS) has opened a Houston training center (HTC). MDS offers weekly IADC and IWCF well control courses, a five-day practical drilling technology course, a five-day advanced drilling technology course and a floater operation transitions course.

Additionally, Willie Lyon has been promoted to vice president and manager of the HTC. E.B. Clapp has joined MDS as manager of well control at the HTC.

Tim Arnold has been promoted to manager of training at the Albuquerque training center, and Bill Murchison Jr. has been promoted to president of MDS.

Andy Hendricks joins Patterson-UTI as COO

William Andrew “Andy” Hendricks Jr joined Patterson-UTI Energy as chief operating officer in April. Mr Hendricks served since 2010 as president of Schlumberger, drilling and measurements division.

It is expected that Mr Hendricks will assume the position of president and CEO upon Doug Wall’s retirement this year.

Stephen Oswald joins Capital Safety as CEO

Stephen Oswald joined Capital Safety in March as its new CEO.

For the last 15 years, Mr Oswald had held various executive roles at United Technologies Corp (UTC), most recently serving as the integration leader for UTC’s acquisition of GE Security.

Burleson appointed director at Cudd Energy Services

Larry Burleson has been appointed director of business development for corporate services at Cudd Energy Services. Mr Burleson will provide leadership in building a global clientele for the company’s integrated solutions. He joins Cudd Energy from Weir Seaboard, where he was vice president of sales.

Tekena Dokubo, GL Noble Denton

Dokubo to lead GL Noble Denton’s new Nigerian base

GL Noble Denton has opened its first base in West Africa with operations in Lagos, Nigeria. The company’s Nigerian operations will provide services and software solutions to aid international and local oil companies in developing and operating safer and more efficient assets in West Africa.

Tekena Dokubo has joined the company to lead GL Noble Denton’s presence in Nigeria. Mr Dokubo brings experience in business development in West Africa’s oil and gas sector.

Vantage Drilling acquires Dragonquest drillship

Vantage Drilling has signed a definitive agreement to acquire the rights and obligations under the construction contract for the ultra-deepwater drillship Dragonquest from Valencia Drilling.

Dragonquest was constructed at Daewoo Shipbuilding & Marine Engineering Co in Okpo, South Korea.

Schlumberger to acquire modeling software company

Schlumberger has entered an agreement with Altor Fund II to acquire SPT Group, which specializes in dynamic modeling. The company provides software and consulting services for multiphase flow and reservoir engineering.

“The dynamic modeling and reservoir optimization software of SPT Group will complement the existing Schlumberger production software portfolio,” Tony Bowman, president, Schlumberger Information Solutions, said.

PRODUCTS

Exxon MZST licensed to Weatherford subsidiary

ExxonMobil Upstream Research Co (URC) has licensed its Multi-Zone Stimulation Technology (MZST) well treatment process to a subsidiary of Weatherford International. The MZST process can be used to stimulate multiple zones in a single operation, yielding improved well economics.

The MZST process can be beneficial for hydraulic fracturing operations in tight gas, shale gas and coal bed methane wells that target multiple reservoir zones, thick reservoir sections or long reservoir intervals where multiple stimulation treatments are required.

“The MZST process is a proven technology for rapidly completing wells in tight reservoirs such as shale gas,” URC president Sara Ortwein said. “This technology will play a key role in improving the economics of developing this unconventional resource.”

The MZST process will enable Weatherford to optimize its stimulation operations by combining the deployment of perforating and hydraulic fracturing equipment simultaneously in the wellbore to enable “single-trip” multi-zone stimulations. The technology increases the number of zones that can be fractured per day compared to traditional fracturing and stimulation operations.

Halliburton’s Q10 pump meets shale fracturing demands

Halliburton has rolled out the first production unit of its new Q10 pumping trailer. The redesigned Q10 pump enhances performance while reducing pumping assets at the well site.

The Q10 units target shale fracturing applications. Performance specifications include a maximum pressure rating of 20,000 lbs/sq in., a range of rates between 2.7 and 18.9 bbl/min, and a power rating of 2,000 hydraulic horsepower.

ConocoPhillips’ Wireline Lubricant designed for HPHT

ConocoPhillips recently launched a new wireline lubricant designed to maintain a seal and prevent the escape of wellbore fluids during wireline operations. Wireline Lubricant is a specialized, clear formulation designed specifically for high-pressure, high-temperature environments.

The lubricant was developed for wireline operations, including cased-hole logging, pipe recovery service, production loggings and reservoir analysis.

Schlumberger’s LWD service supports formation evaluation

Schlumberger recently introduced the MicroScope high-resolution resistivity and imaging-while-drilling service. On a single collar, the logging-while-drilling service provides high-resolution laterolog resistivity and full borehole images in conductive mud environments.

The service has been successful in more than 150 jobs and addresses challenges in unconventional shale plays, carbonate and clastic reservoirs.

Gloves reduce hand fatigue, enable safer work

To safeguard often-forgotten impact and pinch points in high-impact situations, Mechanix Wear’s M-Pact EXP-2, being released in May, has an extended, embossed vinyl cuff designed to dull potential impact to the outer wrist.

The anatomically designed palm pads reduce hand fatigue when the grip is engaged, enabling faster, safer and cleaner work with more power and control.

Mud mixers feature high-efficiency gearboxes

Chemineer mixers offer performance, efficiency and reliability in mud-mixer applications. The Chemineer mixers feature high-efficiency gearboxes designed for agitator service and have configurations to meet application requirements that are unique to mud-mixing applications.

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Analyst: Numbers show that US is drilling its way to zero net oil imports

Horizontal drilling, multi-stage fracturing drive surge in onshore volumes, key to reversing decades-long production decline

By Katherine Scott, editorial coordinator

An increasing US crude production coupled with declining oil demand is resulting in a sharp reduction in the nation’s oil imports, according to Raymond James and Associates. They believe that US oil and gas companies have already worked toward reversing a nearly four-decade-long decline in oil supply. Source: EIA, RJ estimates

Horizontal drilling and multi-stage fracturing are working hard for the industry, and the results are paying off. According to research by Raymond James and Associates, by opening the door to vast resources of unconventional liquids, the industry has radically reshaped the trajectory of US oil production. This is reversing a nearly four-decade-long decline in oil production.

Coupled with declining US oil demand due in part to better vehicle efficiency, the shift is moving the country toward energy independence. Owed to fact that US oil and gas companies have already overcome government road blocks and geological challenges to increase oil supply, and a change in transportation habits has decreased oil demand, Raymond James expects that US net oil imports could reach essentially zero by 2020.

On 22 March at Ohio State University, US President Barack Obama made the claim that the US cannot become energy independent solely by doing more drilling, saying that “we can’t simply drill our way out of the problem.”

Marshall Adkins, managing director, head of energy research for Raymond James, strongly disagrees. “The facts say something very different. The facts say that we are drilling our way out of this. (We’re moving toward being) totally oil independent.”

The recent boost in US oil production, which reached 8.1 million bbl/day last year, and cuts in oil demand are causing imports to fall, which Mr Adkins said is a major part of attaining oil independence for the US.

“It appears that demand will continue to drift lower, but the real driver is more supply, so you combine roughly two barrels of supply growth for every one barrel of decline in demand, and you’re getting pretty meaningful reduction in the amount of oil we need to import,” he explained.

Increasing Oil Supply

Research by Raymond James suggests that the US produced more incremental oil supply than any other country from 2009 to 2011. The growth doesn’t stop there; it is projected that, compared with 2011, there will be a 6% increase in oil production this year and an average 11% growth per year between 2013 and 2015, most of it driven by the ongoing surge in onshore volumes. The use of horizontal drilling and multi-stage fracturing in areas like the Bakken, Eagle Ford and Permian Basin is allowing the industry to get more oil out of the ground.

Declining Oil Demand

Likewise, Raymond James projected that there will be a base decline in oil demand of 1.5% each year through 2020. US oil demand peaked in 2005 at 20.8 million bbl/day, having grown in every year but one since 1992. However, since then, demand has fallen in every year but one, and Raymond James estimates that there will be a decline of 2.5% for 2012 relative to a year ago.

Mr Adkins said that the decline in US oil demand has largely come from higher energy prices, which in turn are pushing better vehicle efficiency, more natural gas vehicles and reduced travel patterns.

Falling oil demand is a smaller but relevant part of the overall story. US oil demand has fallen in every year but one – even in the good economic years of 2006-2007, according to Raymond James and Associates. Source: EIA, IEA, RJ estimates

Decreasing Oil Imports

In light of this increased supply and decreased demand scenario, Raymond James concluded that the US is poised to sharply decrease its dependence on other countries for imported oil. Their research shows net US oil imports already falling from 13.5 million bbl/day (65% of demand) in 2005 to approximately 9.8 million bbl/day (52% of demand) in 2011, and that may fall to an estimated 4.5 million bbl/day (26% of demand) by 2015.

Additionally, lower oil import costs could stimulate resurgence in US manufacturing, bringing with it more jobs.

“This is also a huge boom to US labor, across the board. It’s not just in the energy business, but you know cheap energy creates more manufacturing jobs,” Mr Adkins said, “The single biggest, most visible and immediate benefits to this … is more jobs.”

Us Trade Deficit

Another important aspect to consider is the US trade deficit, where oil imports play a large role. According to the research, oil imports have generated more than half of the total deficit every year since 2007.

“(Decreasing oil imports is) hugely positive for the trade deficit. In the last several years, over half of our trade deficit has been energy related, and if you eliminate that, then your trade deficit gets cut in half,” Mr Adkins said.

Despite adding to the total deficit, the net oil import requirement has dropped every year since 2005, with further declines projected. With an approximately 2.2 million bbl/day reduction in imports since 2008, the US has reduced that part of the deficit by approximately $80 billion annually.

Mr Adkins believes that the resulting savings in the trade deficit are highly meaningful, especially when the benefits of cheaper energy for US manufacturing are taken into account. Further, their research states that the trends of lower oil import costs, cheaper US natural gas prices and decreasing non-oil related trade deficit point to a reduction in the total US trade deficit of 82% by 2020.

Despite these findings, however, Mr Adkins believes there are still additional steps that need to be taken. “(If we increase access to drilling), it will speed up the process of becoming energy independent.”

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Drilling & Completion News

Ensco orders sixth Samsung DP3 drillship for Q3 2014 delivery

Ensco has ordered an advanced-capability, ultra-deepwater drillship to be built by Samsung Heavy Industries in Geoje, South Korea.

The vessel, ENSCO DS-8, will be the sixth Samsung DP3 drillship in the Ensco fleet. It is scheduled for delivery in Q3 2014. The contract also includes options for two additional drillships of the same design.

Consistent with the previous five Samsung ultra-deepwater drillships ordered since 2007, the new unit will have advanced capabilities to meet the demands of ultra-deepwater drilling in water depths up to 12,000 ft and a total vertical drilling depth of 40,000 ft.

New features include retractable thrusters, enhanced safety and environmental features, improved dynamic positioning capabilities and advanced drilling and completion functionality, including below-main-deck riser storage, triple fluid systems, offline conditioning capability and enhanced client and third-party facilities.

Petrobras confirms Tupi Northeast discovery, expands exploration with BP in four blocks

Petrobras has confirmed the discovery of oil in the Tupi Northeast, in the Santos Basin pre-salt. The well, 1-BRSA-976-RJS, is northeast of the Lula field, at a water depth of 2,131 meters and 255 km off the coast of Rio de Janeiro.

The discovery was confirmed by 26° API oil samples, collected from 4,960 meters. An oil column with more than 290 meters in thickness has been identified in the pre-salt carbonate reservoirs.

Petrobras also has a floating, production, storage and offloading vessel, BW Cidade de São Vicente, in the Iracema area (Block BM-S-11) of the Santos Basin. The platform was connected to well RJS-647 at a water depth of 2,212 meters.

The platform will operate for about six months to gather data on the behavior of the reservoirs and the oil flow in the subsea lines. The information will support the development of the final production system, expected to start operations at the end of 2014.

In exploration, BP has been approved to explore four blocks with Petrobras: BM-BAR-3 and BM-BAR-5 in the Barreirinhas basin and BM-CE-1 and BM-CE-2 in the Ceará Basin.

ONRR bills $4 million for BSEE rig inspections

The US Office of Natural Resources Revenue (ONRR) has billed a total of $4,091,100 for the inspection of drilling rigs in Q1 of fiscal year (FY) 2012, specifically billing $1,397,100 in October 2011, $1,447,200 in November and $1,246,800 in December. An estimated 111 oil and gas operating companies were retroactively billed by ONRR in January 2012 after the agency received the authority to do so from Congress.

According to the Bureau of Safety and Environmental Enforcement (BSEE) NTL 2012-N02, lessees and operators have been informed that ONRR will be collecting inspection fees on behalf of BSEE, covering all bottom-founded structures, floating production facilities and drilling rigs. The NTL took effect as of
1 October 2011.

BSEE’s statistics show that 3,964 rigs on the US Outer Continental Shelf were inspected in Q1 FY12. The average weekly number of rigs and non-rig units conducting well operations was 81 in the Gulf of Mexico and 18 in the Pacific region. The Alaska region currently has one federal/state production operation and no drilling activities.

All rigs are inspected on a monthly basis.

Latshaw unveils 1,700-hp diesel-electric/SCR rig

Latshaw unveils 1,700-hp diesel-electric/SCR rig

Latshaw Drilling Co recently added Rig 18 to its fleet. The rig is a 1,700-hp diesel-electric/SCR rig with a 500-ton AC top drive unit and is skiddable for multiwell pad drilling. The rig recently moved to its first location in New Mexico and will be drilling multiple wells from the same pad, with laterals up to 10,000 ft long. The company is now building Rig 19, a 1,500-hp SCR top drive, skiddable rig with 1,600-hp mud pumps that are rated to 7,500 psi.

Ocean Rig receives Letter of Award for deepwater ship

Ocean Rig UDW received a Letter of Award in April for its ultra-deepwater drillship Ocean Rig Olympia from a major oil company. The Letter of Award is for a three-year contract for drilling offshore West Africa.

The contract is expected to commence in continuation of the Ocean Rig Olympia’s existing contract in West Africa. With this contract, Ocean Rig does not have any rigs available in 2012.

Eni starts production offshore Norway, makes discovery in Mozambique

Eni started production in April from the Marulk field in the Norwegian offshore, about 80 km from the coast. The Marulk field is the first that Eni has directly operated in Norway and is part of the PL122 license held by Eni (20%) with Statoil (50%) and DONG Energy (30%).

Marulk is a gas and condensate field, with estimated reserves of 74.7 million bbls of oil equivalent and produces 20,000 boed.

Separately, Eni recently discovered natural gas in Area 4, offshore Mozambique, at the Mamba North East 1 exploration prospect. The results of this well, drilled in the Eastern part of Area 4, increases the resource base of Area 4 by at least 10 trillion cu ft (Tcf).

The discovery improves the potential of the Mamba complex in Area 4 offshore Mozambique, now estimated to have at least 40 Tcf of gas in place.

Eni plans to drill at least four more wells this year in nearby structures to fully assess the upside potential of the Mamba Complex.

Tullow exploratory, appraisal wells strike oil in Kenya

Tullow Oil has encountered in excess of 20 meters of net oil pay in its Ngamia-1 exploration well in Kenya.

The well, in the Turkana County of Kenya Block 10BB, was drilled to an intermediate depth of 1,041 meters and has been successfully logged and sampled. Movable oil with an API rating of more than 30° has been recovered.

The Ngamia structure is the first prospect to be tested as part of a multi-well drilling campaign in Kenya and Ethiopia.

In March, Tullow’s Enyenra-4A appraisal well in the Deepwater Tano licence offshore Ghana encountered oil in sandstone reservoirs. The Owo-1 discovery wells and the Enyenra appraisal well confirm the extent of the Enyenra light oil field.

Results of drilling, wireline logs, samples of reservoir fluids and pressure data show that Enyenra-4A has intersected 32 meters of net oil pay. Pressure data from the oil leg indicates a continuous oil column of approximately 600 meters.

Talisman Energy finds light oil in Kurdamir-2 well

Talisman Energy confirmed the presence of light oil at the Kurdamir-2 well in the Kurdistan Region of northern Iraq in March.

The well flowed at unstimulated rates of 7.3 mmcf/d of natural gas and 950 bbls/day of oil and condensate, with no indications of water and no observed decline.

The Kurdamir-2 well is a re-drill of the Kurdamir-1 gas/condensate discovery well, 2 km away, which was drilled in 2009 but not completed.

Keppel wins contract to build jackup based on LeTourneau design for Perforadora Central

Keppel AmFELS won a contract to build another repeat jackup rig for Perforadora Central.

Keppel AmFELS has won a contract from Mexico’s Perforadora Central to build a repeat jackup rig.

Slated for delivery in Q1 2014, the latest high-specification unit will be based on the LeTourneau Super 116E design with leg lengths of 511 ft and the capability to drill wells up to 30,000 ft in a water depth of up to 375 ft.

Keppel AmFELS completed Tonala, an ultra-premium KFELS B Class jackup rig for Perforadora Central in 2004, followed by Tuxpan, a LeTourneau S116E rig in 2010.

Perforadora Central ordered the Papaloapan jackup in March 2011, and it is under construction and on track for delivery in Q1 2013.

“We have endured the post-Macondo challenges well,” Tan Geok Seng, president of Keppel AmFELS, said. “Having recently secured the Ocean Onyx semisubmersible major upgrade and a series of repairs, this newbuild jackup adds to a healthy workload through Q1 2014.”

Apache expands production in Faghur Basin, Egypt

 Apache Corp recently received approval of seven new development leases in the Faghur Basin, which enables the company to add 5,200 bbl/day of production in Egypt’s Western Desert.

Neilos-2, Apache’s latest Faghur Basin well, test-flowed 6,301 bbls of oil and 4.2 MMcf of gas per day. The well, 0.8 km north from the Neilos-1X discovery, was drilled to appraise the north flank of the Neilos Field and logged 33 ft of net pay in the Jurassic Safa reservoir.

BRS begins to drill its first well in Italy’s Po Valley

BRS Resources announced in March that drilling has commenced on its first well. Located in Italy’s Po Valley, it is a development well in a partially depleted field where 3D seismic technology was used to identify remaining natural gas reserves.

“Using conventional drilling techniques, it will be drilled to a total depth of approximately 6,500 ft (2,000 meters),” Steve Moore, president and CEO of BRS, said. “We have employed state-of-the-art technology to target the reserves and have minimal impact.”

US Interior Department initiates system to accelerate permits, leases

US Secretary of the Interior Ken Salazar recently unveiled initiatives to expedite the development of domestic energy resources on US public lands and Indian trust lands in the Dakotas, Montana and other states.

The Bureau of Land Management (BLM) will implement new automated tracking systems that aim to reduce the review period for drilling permits by two-thirds and to expedite the sale and process of federal oil and gas leases. The system will track permit applications through the review process and flag missing or incomplete information to reduce the back-and-forth between BLM and industry applicants currently needed to amend paper applications.

BLM expects to process 5,500 applications for permits to drill in fiscal year 2012.

Helix completes West African intervention campaign

Helix Well Ops UK’s Well Enhancer mono-hull intervention vessel has completed West Africa’s first well intervention campaign.

Helix Well Ops UK has completed a three-month campaign for West Africa’s first well intervention work and subsea well operations conducted from a mono-hull intervention vessel.

Operating the 132-meter (433-ft) long Well Enhancer, Helix performed a subsea tree change-out, well suspensions, well maintenance and production enhancement on seven wells in water depths up to 471 meters (1,545 ft). The project represents the deepest operation conducted from Well Enhancer since it joined the fleet in 2009.

Well Enhancer marks the emergence of mono-hull-based well intervention services in the region. Intervention programs delivered from mono-hull vessels can provide operational and cost benefits to operators.

“Because Well Enhancer deploys more quickly than a rig and is designed specifically for well intervention work, she reduces down time and helps operators return as quickly as possible to their business of oil and gas production,” Steve Nairn, Helix Well Ops regional vice president of Europe and Africa, said.

North Atlantic confirms order of harsh-environment semi

North Atlantic Drilling has entered a turnkey construction contract with Jurong Shipyard in Singapore for the construction of a new harsh-environment semisubmersible drilling rig.

The rig will be of a Moss CS60 design, N-Class compliant and be fully winterized.

BG Group begins first production from the Gaupe

BG Group has begun production from the Gaupe field in the Norwegian North Sea. With estimated gross recoverable reserves of approximately 30 million bbls of oil equivalent, production from Gaupe is expected to reach a plateau production rate of around 15,000 boed in Q3 this year.

Anadarko encounters natural gas in Mozambique

Anadarko Petroleum’s Barquentine-4 appraisal well proved successful offshore Mozambique, the company said in April. The well in Offshore Area 1 of the Rovuma Basin encountered approximately 525 net ft (160 meters) of natural gas pay and became the Anadarko partnership’s ninth successful well in the complex.

In March, the company achieved oil production at the Caesar/Tonga development in the Green Canyon area of the deepwater Gulf of Mexico. Production from Caesar/Tonga, with an estimated resource base of 200 million to 400 million bbls of oil equivalent, is expected to ramp up to approximately 45,000 boed from the first three subsea wells.

Atwood awarded contract for newbuild jackup

Atwood awarded contract for newbuild jackup

Atwood Oceanics has been awarded a contract by Salamander Energy (Bualuang) for the newbuild jackup Atwood Mako. The award is for a firm duration of 12 months for work offshore Thailand. The rig is under construction with PPL Shipyard in Singapore.

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