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First LNG-Fueled Hydraulic Fracturing Completed in Eagle Ford Play

by  Karen Boman
Rigzone Staff

The liquefied natural gas (LNG) division of Calgary-based Ferus LP successfully completed in October what the company believes to be the first-ever hydraulic fracturing operation utilizing liquefied natural gas (LNG) as engine fuel in North America.

Ferus’ LNG Division was engaged by a major oil and gas service company in the United States to conduct the pilot project, which involved six dual-fuel 2,250 horsepower pressure pumper units, powered by LNG, to stimulate well performance in the south Texas Eagle Ford shale.

The dual fuel systems allow for natural gas and diesel to be consumed simultaneously with no decrease in performance, Jed Tallman, manager of market development for Ferus LNG, told Rigzone. Approximately 10,000 gallons of LNG was used in the pilot project, which took place in the southwestern portion of the Eagle Ford play.

While the company cannot discuss the plans of the operator involved in the pilot project, Ferus LNG has been contacted by numerous operators and service companies regarding LNG as a low-cost, environmentally superior alternative fuel, Tallman said.
The increase in interest by operators and service companies in using LNG for hydraulic fracturing has been dramatic.

“Because of the large amounts of diesel consumed in fracturing fleets, the use of LNG as an alternative fuel will result in cost savings for the operator or service company, not to mention a significant reduction in greenhouse gas emissions,” Tallman commented.

“LNG offers significant environmental and cost-saving advantages and is quickly becoming the alternative fuel of choice for heavy-duty high horsepower on-road and off-road applications in North America,” said Ferus President and CEO Dick Brown in a Nov. 28 statement. “We were very pleased to play such a critical role in this ground-breaking project, and we intend to be at the forefront of this growing industry as more and more diesel consumers make the switch to North America’s abundant supply of natural gas.”

It is difficult to estimate the specific size of the market for LNG in hydraulic fracturing and in other areas such as railroad transportation and trucking moving forward, Tallman commented.

“But given the economic benefits, improved emissions profile, and increased gas production, we feel that LNG will make up a considerably larger percentage of our domestic energy consumption in the future.”

While the use of LNG for hydraulic fracturing is not being specifically done to alleviate criticism of hydraulic fracturing, the improved emissions profile of natural gas certainly is a benefit, Tallman said.

To complete this project, which marks a significant milestone in the adoption of natural gas as an alternative engine fuel, Ferus managed the entire supply chain on behalf of its client including LNG supply, transportation, and on-site storage and vaporization using specialized equipment and highly-trained personnel.

In addition to being a cleaner-burning and less expensive fuel alternative, LNG is non-toxic, non-combustible, non-flammable as a liquid, and dissipates into the atmosphere in the event of a leak or a spill, making it safer than diesel and gasoline, the company said in a statement.

The use of LNG requires specialized fuel handling equipment and additional training for individuals involved in the LNG supply chain.

“As a leading provider of cryogenic liquids for the energy sector, Ferus is uniquely qualified for the undertaking,” Tallman said.

The increased use of natural gas to fuel not only hydraulic fracturing but transportation has grown thanks to the abundance of shale gas in the United States.

The use of natural gas over diesel is becoming more widespread, likely due to the cost benefits associated with fuel switching, according to a Nov. 28 analyst report from GHS Research. GHS referenced Baker Hughes‘ Nov. 26 announcement that it would convert a fleet of its Rhino hydraulic fracturing units to bifuel pumps as a way to improve operational efficiency, lower costs and reduce health, safety and environment impacts. Bifuel is a mix of gas and diesel.

The new pumps use a mixture of gas and diesel, reducing diesel use by up to 65 percent with no loss of hydraulic horsepower. The converted fleet, which meets all U.S. Environmental Protection Agency emissions standards, can also reduce a number of emissions including nitrogen oxides, carbon dioxide and particulate matter.

Baker Hughes first converted a small fleet of its units in Canada; the success Baker Hughes saw with this endeavor prompted to company to convert an entire fleet in the United States. The company is converting several more fleets of Rhino trucks to Rhino Bifuel equipment. Baker Hughes also has a test program in Oklahoma, where a number of light-duty vehicles have been converted to natural gas.

Westport Innovations, which manufactures natural gas-powered truck engines, recently reported it is building a railroad locomotive engine that can run on LNG. During 2012, the company saw “broad consensus” for the first time that natural gas will take material market share in every global transportation market within the next five years, said David Demers, chief executive officer for Westport, during the company’s third quarter 2012 earnings update Nov. 8.

Demers noted that consensus suggests that the company will see 7 percent to 15 percent of the North American trucking industry run on natural gas in 2017.

Westport Innovations will also introduce new natural gas-powered versions of the Ford F-450 and F-550 Super Duty trucks in mid-2013, the company said in a Dec. 3 statement.

“Although current demand for natural gas used in vehicles is minor relative to the demand associated with power generation, industry and residential heating, it is catching on and may soon reach a tipping a point where growth rapidly accelerates, with or without government intervention,” GHS reported.

Source

Baker Hughes Sees Rise in May 2012 Rig Numbers

Baker Hughes

by  Baker Hughes
Press Release
Friday, June 08, 2012
 
Baker Hughes announced Thursday that its worldwide rig count for May 2012 was 3,335, up 38 from last month.
 
The company’s international rig count, which excludes its rigs in the United States and Canada, for May was 1,225, up 47 from last month.
The company’s US rig count for May was at 1,977, up 16 from last month. Its Canadian rig count for the same period was 133, down 25 from its number last month.

RIGZONE – Baker Hughes Sees Rise in May 2012 Rig Numbers.

Bexar facility is ‘big deal for us’

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Robert Drummond, president of Schlumberger North America, (left) talks about his company as Jeremy Aumaugher, south division operations manager, listens to questions about expansion of their business to support clients in the Eagle Ford Shale.

Photo: TOM REEL, San Antonio Express-News / San Antonio Express-News
By Vicki Vaughan
Updated 12:26 p.m., Thursday, March 8, 2012

Schlumberger, the world’s largest oil-field services company, threw open the doors Wednesday to its new operations plant in southern Bexar County, where it was drawn by proximity to the Eagle Ford Shale.

“This is a big deal for us,” Robert Drummond, president of Schlumberger North America, said as he stood before shiny trucks in a spic-and-span warehouse that’s part of a $19 million investment.image

The new facility is a critical addition to Schlumberger’s south division operations, which encompasses the New Mexico, West Texas and South Texas, he said.

Construction of the company facilities, which occupy three sites on Fischer Road near the intersection of Interstate 35 South and Loop 410, began in December 2010, company officials said.

Schlumberger — which is based in Houston, Paris and The Hague, Netherlands — employs almost 400 in the San Antonio area, a total that is likely to grow to 500 employees in the coming months, officials said.

San Antonio’s nearness to the shale has meant that the company hasn’t had a problem recruiting employees, whose work ethic “is excellent,” Drummond said.

The South Bexar facility employs managers, engineers, health and safety employees, equipment operators, maintenance and electronic technicians, and laboratory workers.

Salaries at the operations center range from $25,000 to $85,000 a year, said Jeremy Aumaugher, south division operations manager for pressure pumping. Employees also are eligible for performance bonuses, he said.

However, some employees may work 60 hours a week or more and be away from home for periods of time, Aumaugher said.

The company’s biggest labor needs are for truck drivers, while mechanics and electronic technicians make up another key category, he said.

“We’re in competition, obviously, with others who do the same work as us,” Drummond said. “We want to be the employer of choice in North America, meaning not only (in) compensation but work conditions, facilities and safety environment.”

Schlumberger’s center will handle its customers’ demands for pressure pumping, which is used to enhance the flow of oil and natural gas in hydraulic fracturing. It also will provide cementing services, a process used to surround a well’s casing, or pipe.

Schlumberger’s operations occupy 60 acres. One facility occupies a 35-acre site that includes bays for maintaining, fueling and washing trucks. There’s a 15-acre bulk plant capable of storing 20 million pounds of sand for use in hydraulic fracturing, a cement blending area, a 39,028-square-foot warehouse, a laboratory and a support and training facility on 10 acres.

At a ceremony Wednesday at Schlumberger, Economic Development Foundation Chairman Henry Cisneros said: “This is a great, global company doing important work. The more you can succeed here, it is ‘mission accomplished’ for us.”

As drilling in the Eagle Ford Shale has exploded, a number of oil-field services companies have established a presence in the region, including Houston-based Halliburton Co. and Baker Hughes Inc., Switzerland-based Weatherford International Inc. and Canada-based Sanjel.

In addition, a number of oil production companies drilling in the Eagle Ford Shale have opened offices in San Antonio.

vvaughan@express-news.net

Source

Schlumberger to Acquire Norway-Based SPT Group

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Schlumberger announced that it has entered into an agreement with Altor Fund II to acquire SPT Group—a privately owned software company specialized in dynamic modeling for the oil and gas industry.

The company provides a combination of software and consulting services for multiphase flow and reservoir engineering applications. Closing is subject to customary regulatory approvals.

“The dynamic modeling and reservoir optimization software of SPT Group will complement the existing Schlumberger production software portfolio,” said Tony Bowman, President, Schlumberger Information Solutions (SIS). “In combination with the Petrel* E&P software platform and other SIS technologies, this will enable customers to further optimize production from reservoir performance to processing facilities.”

“This is a great testament to our employees and a remarkable opportunity for the company,” commented Tom Even Mortensen, Chief Executive Officer of SPT Group. He continued, “Combining the skills, abilities, presence and technologies of the two companies will further increase the scale of our activities and enable continued delivery of products and services with the quality and pace the market demands.”

SPT Group Chairman and Altor Partner Reynir Indahl added, “We are proud to have developed a very successful company together with SPT Group management, and believe that Schlumberger will be a great home for SPT and its employees.”

SPT Group, founded in 1971, is headquartered in Norway and employs approximately 280 people in 11 countries worldwide. The company is a leader in dynamic modeling of multiphase flow and reservoir optimization through renowned software products and a global team of professional consultants. SPT Group has invested more than most comparable firms in developing cutting-edge technology. The company’s employees, global presence, close ties to industry research environments, and clear focus on customer needs have been important factors in its success.

Source

Insight: Natural gas pain is oil’s gain as frack crews head to North Dakota

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By Selam Gebrekidan
NEW YORK | Mon Mar 19, 2012 4:43am EDT

(Reuters) – Collapsing natural gas prices have yielded an unexpected boon for North Dakota‘s shale oil bonanza, easing a shortage of fracking crews that had tempered the biggest U.S. oil boom in a generation.

Energy companies in the Bakken shale patch have boosted activity recently thanks to an exceptionally mild winter and an influx of oil workers trained in the specialized tasks required to prepare wells for production, principally the controversial technique of hydraulic fracturing.

State data released this month showed energy companies in January fracked more wells than they drilled for the first time in five months, suggesting oil output could grow even faster than last year’s 35 percent surge as a year-long shortage of workers and equipment finally begins to subside.

As output accelerates, North Dakota should overtake Alaska as the second-largest U.S. producer within months, extending an unexpected oil rush that has already upended the global crude market, clipped U.S. oil imports, and made the state’s economy the fastest-growing in the union.

Six new crews trained in “well completion” — fracking and other work that follows drilling — have moved into North Dakota in the past two months alone, according to the state regulator and industry sources. Back in December, the state was 10 crews short of the number needed to keep up with newly drilled wells.

“Three to four months ago, the operators were begging for fracking crews,” said Monte Besler, who consults companies on fracking jobs in North Dakota’s Bakken shale prospect. Now “companies are calling, asking if we have a well to frack.”

For the last three years, smaller oil companies with thin pockets were forced to wait for two to three months before they could book fracking crews and get oil out of their wells. As more and more wells were drilled, that backlog has grown.

Last year, an average 12 percent of all oil wells were idled in North Dakota. Even so, output in January hit 546,000 barrels per day, doubling in the last two years and pushing the state ahead of California as the country’s third-largest producer.

FEWER WELLS IDLE

Fracking, which unlocks trapped oil by injecting tight shale seams with a slurry of water, sand and chemicals, has drawn fierce protests in some parts of the country, but it has not generated heated opposition in North Dakota.

The number of idle wells waiting to be completed in the state reached a record 908 last June, the result of a new drilling rush and heavy spring floods. Only 733 wells were idle in August as crews caught up, but the figure crept steadily higher until the start of this year.

Now, the industry may be turning a corner in North Dakota, the fastest-growing oil frontier in the world.

“Both rig count and hydraulic fracturing crews are limiting factors. Should they continue to rise together, production will not only increase, it will accelerate,” said Lynn Helms, director of the state Industrial Commission’s Oil and Gas Division.

The tame winter likely played an important role in helping reduce the number of idle wells — those that have been drilled but not yet fracked and prepped for production. That number fell by 11 in January, as oil operations that would normally be slowed by blizzards were able to carry on, experts said.

Residents of the northern Midwest state — accustomed to temperatures as low as minus 40 degrees Fahrenheit (-40 Celsius) in winter and snow piles as high as 107 inches — this year enjoyed the fourth warmest since 1894, according to the National Weather Service.

The milder conditions also helped prevent the usual exodus of warm-weather workers that occurs when blizzards set in.

“Not everyone wants to work in North Dakota in the winter,” Besler said.

The backlog of unfinished wells has also begun to subside because the pace with which new wells are drilled has leveled off. The state hasn’t added new rigs since November.

The latest state data shows oil companies brought 37 new rigs to North Dakota’s in 2011 but have not added more since November. The rig count held steady at 200 in January 2012, although more than 200 new wells were drilled in that period.

SLUMPING NATGAS PRICE PROVIDES RELIEF

North Dakota has gotten a boost from the fall-off in natural gas drilling due to the collapse in prices to 10-year lows. Energy companies such as Chesapeake and Encana have shut existing natural gas wells and cut back on new ones. Last week, the number of rigs drilling for gas in the United States sank to the lowest level in 10 years as major producers slimmed down their gas business, according to data from Houston-based oil services firm Baker Hughes. [ID:nL2E8EG9OY] The fewer gas wells drilled, the less need for skilled fracking crews in the country’s shale gas outposts.

Fracking in oil patches is similar to the process used in gas wells, except for the inherent power of the pumps employed. Crews inject high-pressure water, sand and chemicals to free hydrocarbons trapped in shale rock. So big service firms such as Halliburton, Baker Hughes and Schlumberger  are reshuffling crews from shale gas fields to oil prospects in the badlands. “We have moved or are moving about eight crews. Some of those crews are moving as we speak,” Mark McCollum, Halliburton’s chief financial officer, said at an industry summit in February.

Halliburton declined to specify where the crews were moving.

Calgary-based Calfrac moved one crew into the Bakken in late 2011, according to an SEC filing. Privately owned FTS International no longer works in the gas-rich Barnett shale but has set up operations in the Utica, an emerging prospect in Ohio and western Pennsylvania, according to a company representative.

The reallocations come with some efficiency losses. Halliburton had to scale back its 24-hour operations and is still trying to solve logistical problems. “You actually take the crew from one basin and they have to go stay in motels, you have to pay them per diems for a while. And then you have to double up your personnel while you’re training new, locally based crew on the equipment once it is moved,” McCollum said.

At the same time, a shortage of key equipment such as pressure pumps is easing as companies start taking delivery of material ordered months or even years ago.

It takes about 15 such pumps to frack a gas well, and many more for oil wells. The total pressure-pumping capacity in the United States at the end of 2012 will be 19 million horsepower, two-and-a-half times more than in 2009, according to Dan Pickering, analyst with Tudor Holt and Pickering in Houston.

FRACKING AROUND THE NATION

Easing personnel constraints suggest recruiters may be meeting with success in nationwide campaigns to attract workers with specialized knowledge of complex pumps and hazmat trucks — and a willingness to brave harsh conditions.

Even with U.S. unemployment at 8.3 percent, such skilled labor remains in short supply despite salaries from $70,000 to $120,000 a year. In North Dakota, unemployment was just 3.2 percent in January, the lowest rate in the nation.

Fracking crews, much like roughnecks on drilling rigs, clock in 12-hour shifts for two straight weeks before getting a day off. They live in camps far from cities and towns. Jobs are transient — a few weeks at a single location. Most workers divide their time between the California desert, Texas ranchlands and the freezing badlands of the Midwest state.

Companies have scrambled to nab talent, with recruiters scouring far and wide. Military bases have gotten frequent visits, and some companies have hired truckers from Europe.

“There’s definitely a push to look all over for people who have good experience since it takes at least six months to train someone how to use a fracking pump,” said David Vaucher, analyst with IHS Cambridge Energy Research.

(Editing by David Gregorio)

Baker Hughes Bringing High-End Well Stimulation Vessel to North Sea

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Baker Hughes Incorporated, announced that its subsidiary has chartered a new state-of-the-art pressure pumping vessel that will provide offshore stimulation services to Maersk Oil in the North Sea. Upon completion, scheduled for late 2013, the Blue Orca(TM) will become the eighth vessel in the Baker Hughes fleet.

“We are pleased to be working with Maersk Oil as we expand our current fleet into the North Sea,” said Art Soucy, Baker Hughes’ President of Global Products & Services. “Our full cadre of world-class stimulation vessels offers customers the capacity, performance and redundancy for round-the-clock operations that are needed in today’s offshore plays. We are committed to operating safely and efficiently while continuing to build on our pressure pumping market leadership and the challenging offshore environments where operators need us to be.”

The Blue Orca will be rated to 15,000 psi and will offer among the largest fluid and proppant carrying capacities in the world. It will provide 15,000 hydraulic horsepower pumping capacity and the ability to pump at rates well in excess of 60 bpm. Engineering work on the marine and stimulation systems has already begun.

“Stimulation of long horizontal wells is one of Maersk Oil’s key technologies and vital for economic development of our tight chalk reservoirs,” said Mary Van Domelen, Maersk Oil’s Stimulation Team Leader. “We appreciate the opportunity to work with Baker Hughes to deliver a new state-of-the-art stimulation vessel and look forward to welcoming the Blue Orca to the North Sea.”

The Blue Orca will join Baker Hughes’ other stimulation vessels – including the company’s newest additions to the Gulf of Mexico: Blue Tarpon and the Blue Dolphin. The vessels support offshore completion operations and will be equipped to support high-rate and high-volume multi-zone fracturing operations.

“Our pressure pumping vessels offer enhanced safety systems with redundant back-up blending and pumping capabilities,” said Lindsay Link, Baker Hughes’ President of Pressure Pumping.When it comes to performing multi-zone, high-rate, high-pressure completions, our vessels are reliable, efficient and minimize delays in high-cost offshore environments, where time is of the essence for the operators on behalf of whom we are working.”

Source

Baker Hughes Rig Counts: International Offshore Rigs Up by 11 (USA)

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Baker Hughes Incorporated announced today that the international rig count for February 2012 was 1,204, up 33 from the 1,171 counted in January 2012, and up 15 from the 1,189 counted in February 2011.

The international offshore rig count for February 2012 was 320, up 13 from the 307 counted in January 2012 and up 11 from the 309 counted in February 2011.

The US rig count for February 2012 was 1,981, down 27 from the 2,008 counted in January 2012 and up 282 from the 1,699 counted in February 2011. The Canadian rig count for February 2012 was 701, down 19 from the 682 counted in January 2012 and up 78 from the 623 counted in February 2011.

The worldwide rig count for February 2012 was 3,886 up 25 from the 3,861 counted in January 2012 and up 375 from the 3,511 counted in February 2011.

The Baker Hughes Rotary Rig Counts are counts of the number of drilling rigs actively exploring for or developing oil or natural gas in the United States, Canada and international markets. Baker Hughes has issued the rotary rig counts as a service to the petroleum industry since 1944, when Hughes Tool Company began weekly counts of US and Canadian drilling activity. Baker Hughes initiated the monthly international rig count in 1975.

Source

Barite Market Tight as China Supplies Decrease

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by  Jaime Kammerzell | Rigzone Contributor

Tuesday, December 20, 2011

There is a growing shortage of barite supply, which has the oil and gas drilling industry looking for alternatives. Barite, the mineralogical name for barium sulfate, is used primarily in oil and gas drilling, but also is used as non-toxic filler, extender or weighting agent in plastics, paints and rubber, and as a shield around nuclear power plants. It also has medical uses such as blocking x-ray and gamma-ray emissions, and a pharmaceutical grade barite is used for barium milkshakes for intestinal x-rays.

To understand the barite market today, Brian O’Connell, Senior Category Manager of Mined Products, Baroid Supply Chain Group of Halliburton, explained that “the cost of barite over the past 10 years has quadrupled, in the last 5 years it has tripled, and over the past 2 years it has doubled.”

In addition to the cost increase, a decrease in quality related to metals and contaminants and a decrease in availability of 4.2 g/cu cm, which has historically been the API specification, are contributing to the current supply issues.

Global Barite Production

Most barite comes from China, which was responsible for 51 percent of the global supply in 2010. India had a 14 percent share of the barite market followed by the U.S. with 9 percent, Morocco with 7 percent and the rest of the world with 19 percent, according to the Barytes Association. Mined barite in 2010 totaled 7 million tons.

“China is the major barite source and leads the market,” O’Connell said.

2010 Barite Production By Country

China’s mining industry is undergoing a safety overhaul as many accidents and deaths in non-oil and gas related mining industries have prompted the government to enforce stricter regulations comparable to U.S. regulations. With these new regulations comes additional expense that smaller mines can’t meet. Thus, the supply burden has fallen on the larger mines.

However, in some cases, the local and regional Chinese authorities have reduced production from the larger mines.

“Up until about 2 1/2 years ago in Xiangzhou County, otherwise known as Elephant County, in Guangxi province, the Chinese were producing 1.2 million tons of barite per year. This year, the volume has fallen to 300,000-350,000 tons, which is a reduction of almost 1 million tons out of China,” O’Connell explained. “With global barite production of 7 million tons in 2010, a 1 million ton reduction is a big hit to the market.”

To add to the cost, as miners produce more and more barite, they have to dig deeper and further away from export ports. Recent weather-related problems like flooding, droughts and earthquakes not only impacted barite mining, but also transportation to these export ports.

O’Connell also points to the U.S. dollar/Chinese Yuan exchange rate, which has seen a 25 percent change since 2005, as a source of rising barite costs.

According to O’Connell, the high level of worldwide drilling activity correlates to an increase in barite demand. Peak demand and a reduction of barite coming out of China are driving the price and quality issue. “With this kind of imbalance, the scale tips in favor of sellers,” O’Connell said.

India’s barite market also is impacting the global barite market. India is the second largest producer of barite in the world. However, the country only has one major source of barite and the government owns it. The government entity that manages the mine, APMDC, holds two tenders every three years. The first tender calls for bids to mine the barite, and the lowest qualified bid wins the business. The second tender calls for bids for the barite that comes out of the mine. This goes to the highest qualified bidder.

The latest tender in 3Q 2011 resulted in a dramatic overnight price increase of more than 70 percent on a freight on board (FOB) Chennai basis.

U.S. Barite

The United States produced about 9 percent of the world production in 2010 of barite and imports much of its demand. As major world-wide buyers, Baroid and other fluid service companies typically ship in large lot sizes — 60,000 tons in one shipment — from China to the U.S. Gulf Coast. But Chinese traders are having increasing difficulties accumulating that much material at one time, O’Connell explained, and as a result, lower quality material is making its way into cargoes to fill out vessels, resulting in inconsistent material quality.

Back in 2006, a major barite producer with Nevada mining operations converted to a lower grade of barite, 4.1, to extend their U.S. reserve base and reduce their reliance on imports. According to O’Connell, Baroid immediately followed, and the other two barite producers in Nevada followed soon after.

The Baroid mine in Dunphy, NV
The Baroid mine in Dunphy, NV

The 4.2 and 4.1 barite grades from U.S. sources have basically the same types of impurities. All four of the Nevada producers sold the lower grade product prior to API approval with general customer acceptance. At the same time that this grade was being used in the field, the four major fluid service companies encouraged API to add the lower grade to the approved products list, which has been done.

“We are trying to get operators to stop using material that has a higher density than what they really need. As an industry, we’ve been pretty successful,” O’Connell explained.

O’Connell indicated that the trend toward 4.1 barite is spreading globally and is helping to reduce pressure on miners to dig deeper for of 4.2 barite.

Regardless, the current supply is so tight, fluid service companies are considering alternative materials or even lighter weight barite than 4.1.

“We’ve looked at hematite and calcium carbonate, but each has characteristics not suitable for weighting of mud like barite, which is why we are looking into lighter barite instead of alternatives,” O’Connell said.

Source – RIGZONE

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