Land Rigs: Targets

Showing posts with label Targets. Show all posts

Wednesday, July 10, 2013

Total Confirms Output Targets, Sees Further Growth After 2017

SHETLAND, Scotland - French company Total SA still expects its oil and gas output to grow 3% on average on an annual basis between 2011 and 2015, and then sees accelerated growth after 2017 as new projects come on stream, the head of the exploration and production division Yves-Louis Darricarrere said, ahead of the group's release of its first-quarter earnings later this week.

By 2017, the group expects to have increased its production capacity potential to 3 million barrels of oil equivalent per day, from currently around 2.3 mboe/d, Mr. Darricarrere said during a press presentation there Monday.

The group is strongly competing with peers to find more oil and gas as energy demand keeps growing in emerging markets and while most conventional hydrocarbon reservoirs around the world are believed now to be depleting. Total has engaged in a strategic change and has become more aggressive in terms of exploration, allowing it to recently make substantial discoveries, notably in risky areas also called "frontier basins," such as the rough seas of West Shetlands and the Barents Sea, at the most northern tip of Europe.

Total even sees its output growth accelerating after 2017, as "already 90% of the 2017 potential is either in production or in development," Mr. Darricarrere said.

"We're seeing the results of our revitalized exploration strategy. Accepting to take more risks and looking for larger projects are our new focuses," Mr. Darricarrere said, adding the group's potential resources has doubled in the last three years to six billion barrels of oil equivalent.

In the North Sea alone, the group plans to invest as much as $20 billion over the five coming years, he said.

The strategy has allowed Total's production decline rate to remain steady, at around 3%, he said.

"We're able to control the decline, but this is because attention has been brought to existing fields and all our projects must be on time... Any delay of a project is a destruction of growth," he added.

Total has currently 15 projects under development, four of which are located in the North Sea and the Barents Sea. Mr. Darricarrere said "these projects, for the time being, are on time" and should add around 175,000 boe/d to Total's production.

The group will release its first-quarter earnings on Friday at 0600 GMT. Analysts polled by Dow Jones Newswires expect Total's first-quarter output to have dropped 2.1% from a year earlier to 2.323 mboe/d from 2.372 mboe/d.

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Tuesday, July 9, 2013

Total Confirms Output Targets, Sees Further Growth After 2017

Total even sees its output growth accelerating after 2017, as "already 90% of the 2017 potential is either in production or in development," Mr. Darricarrere said.

In the North Sea alone, the group plans to invest as much as $20 billion over the five coming years, he said.

The strategy has allowed Total's production decline rate to remain steady, at around 3%, he said.

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Monday, June 24, 2013

Legislation Targets Mandates for Water Recycling in Oil, Gas Industry

Legislation introduced last week into the Texas Legislature mandating the recycling of produced and flowback water from hydraulic fracturing operations mark the most recent efforts by lawmakers to make water recycling mandatory.

With Texas' population expected to reach 46.3 million people over the next 50 years, drought conditions over the past three years and water shortages over the past five years, oil and gas and other industries that consume a significant amount of water have been scrutinized by the public, environmental groups and government officials. Texas does not have enough existing supplies today to meet demand for water in times of drought, according to Texas' State Water Plan.

Concerns about water usage have grown in recent years not only in Texas, but communities across the United States, said Gabriel E. Eckstein, an attorney with the law firm Sullivan & Worcester and a professor specializing in water, environmental, natural resources and international law at Texas Weslayan University School of Law in Fort Worth, in an interview with Rigzone. In recent years, a host of water-related bills from the construction of new dams to aquifer storage to water recycling have been introduced to the state legislature, Eckstein commented. Major discussions have also taken place to use money from the state's Rainy Day Fund as seed money for infrastructure to meet Texas' future water supply needs.

The surge in exploration and production and unconventional resources in the Eagle Ford and other shale plays in Texas has created concerns in recent years over the amount of water being used in hydraulic fracturing and hydraulic fracturing's impact on local water supplies. The hydraulic fracturing process involves injecting a mixture of water, sand and chemicals into a well at high pressure to create fissures to release oil and gas deposits. Water usage varies on the size and conditions of the shale formation, with Haynesville shale requiring close to 8 million gallons per well, followed by the Eagle Ford play at 5 million and Barnett shale at over 4 million gallons.

From 2008 to 2011, total water used in hydraulic fracturing in Texas grew from 36,000 in 2008 to 81,500 acre-feet in 2011, according to "Oil and Gas Water Use in Texas: Update to the 2011 Mining Water Use Report". In 2011, the oil and gas industry used 102,500 acre-feet of water, including approximately 81,500 acre-feet for hydraulically fracturing wells and approximately 21,000 acre feet for other oil and gas industry purposes.

Water used in oil and gas exploration, development and extraction and for mining represented 1.6 percent of Texas' total water use, while irrigation and municipal water use collectively represented 82.8 percent of water use in the state, according to the Texas Water Development Board's 2012 State Water Plan. However, in the Eagle Ford shale region, mining accounts for 6.5 percent of water demand; that demand is expected to increase by 26 percent from 2010 to 2060 for the region, according to Luke Metzger, head of Environment Texas.

While water demand for municipal use, manufacturing, and steam electric power generation are expected to rise over the next 50 years, water demand for oil and gas and mining is expected to remain relatively constant and then decline over that period. By 2060, mining water use is expected to decline slightly from 1.6 percent to 1.3 percent for Texas' total water use, according to "March 2013 Eagle Ford Shale Task Force Report".

Last month, the Texas Railroad Commission (TRC) adopted rules to encourage Texas oil and gas operators to continue conserving water used in hydraulic fracturing. These new amendments do not make recycling mandatory for operators.

"However, they are expected to encourage recycling by eliminating the need for a permit for on lease fluid recycling, streamlining the recycling permitting process and providing operators with clear path to securing the Commission permits," a TRC spokesperson told Rigzone in an email.

The TRC's new and updated recycling rules authorize an operator or its contractor to store and recycle well fluids on an oil and gas lease, allow the operators to recycle each other's fluids, and establish protective standards for fluid storage and recycling, the spokesperson said.

For recycling activity that requires a permit, the rules clearly identify application requirements and establish categories of commercial recycling permits to reflect industry practices in the field, the spokesperson said. The amended rules are scheduled to take effect April 15.

Despite the new TRC regulations, some state lawmakers have sought to take matters a step further and require oil and gas operators to recycle water. House Bill 2992, introduced by Rep. Tracy O. King (D-Batesville) would prohibit hydraulic fracturing flowback fluid and water produced from a hydraulically fractured well from being injected into a disposal well unless the fluid cannot be treated so it could be recycled in hydraulic fracturing, used for another beneficial purpose or be released into or near the state's water system.

The bill would also require the TRC to adopt rules establishing standards for determining whether flowback and produced water may be disposed of in an oil and gas waste disposal well.

The TRC has said it would need to track flowback fluid from the point of generation to the point of ultimate disposition for beneficial use or disposal, with certification that the fluid cannot be treated for beneficial use to allow disposal into an injection well. This would require additional inspections; the TRC estimates it would need an additional 16,200 inspections to track this data.

These inspections would be conducted on a different schedule from the current inspection workload, and would focus on tracing the origins and use and treatment of flowback fluid. To implement this bill, 21 full-time employees would be needed, including three at the TRC headquarters to manage the tracking system and to enforce the new requirements, as well as two full-time inspectors at each of the agency's nine district offices to enforce the bill's requirements. These costs are estimated at approximately $1.4 million per fiscal year.

The TRC would also need to establish a complex water tracking system to determine water treatment and ultimate disposal. To track flowback and produced fluid and their method of disposal, the TRC would have to develop an application that would allow for operators to file the volumes of flowback and produced water from an oil and gas well on a monthly basis, along with how these volumes are disposed. The estimated cost to develop the necessary technology in 2014 is $486,720.

HB 3537, introduced by Rep. Roland Gutierrez (D-San Antonio) would require the TRC to adopt rules requiring treatment of flowback and produced water from oil and gas wells that have been hydraulically fractured. The bill would only apply to fluid produced from an oil and gas well on or after the bill's effective date.

Both bills would require TRC to adopt the new rules no later than Dec. 1 of this year, and would take effect Sept. 1, 2013. The legislation does not expect HB3537 to have any significant fiscal impact to the agency.

The new bills aren't the first time lawmakers have sought to make recycling of water from hydraulic fracturing operations mandatory. During the 2011-2012 session, Rep. Lon Burnam (D-Forth Worth) proposed HB 378, which would have required oil and gas operators to pay $.01/barrel tax for every barrel of hydraulic fracturing wastewater injected into a disposal well. That measurement did not pass.

Environment Texas voiced support for HB 2992 and HB 3537, noting that the statewide percentage of water demand in oil and gas drilling and mining belies the impact of oil and gas extraction on water supplies in the few areas of the state where oil and gas production is most prevalent, said Metzger in a statement to Rigzone.

However, oil and gas industry executives say incentives, not mandates, are the best way for Texas to encourage oil and gas operators to recycle water from hydraulic fracturing operations.

"The TRC deserves credit for creating rules that are fair and that help remove impediments to increased recycling in Texas," said Brent Halldorson, chief operating officer of water recycling firm Aqua-Pure/Fountain, told Rigzone in an email.

Recycling is being actively included in exploration and production companies' water management strategies, Halldorson added.

The rules already adopted by the TRC which would allow recycling without acquiring a new permit to do so actually go a long way to encourage recycling compared to a mandate, and for exploration and production companies to adopt recycling, mainly because they can store the water onsite so that they can recycle it, said Anthony Migyanka, CEO of Irving, Texas-based water treatment firm CLLEEN, in a statement to Rigzone.

Texas exploration and production companies have built-in incentives to recycle: water scarcity, drought and transportation costs, Migyanka commented.

"I think if they give them time to play out, the drillers and their water treatment vendors will find better recycle economics versus just taxing them into doing it. And long-term, they would benefit everyone using water."

"It would take a $3/bbl brine well injection tax, not a $.01/bbl tax, at least theoretically, to change the workflow from disposal to recycle, but I don't know that it would improve the economics of recycling water, which is really what Texas wants, and it's what the drillers want too," Migyanka commented. "It would just cause price inflation. What if the drillers simply decide to pay the tax? That's not saving any water, which is the point of the proposed legislation."

The amount of water recycled from hydraulic fracturing is difficult to pinpoint, Migyanka noted. Metzger noted that the low level of flowback water recycled in Texas is partly due to the high cost associated with treating this water. An estimated 5 percent of Barnett shale flowback is recycled and reused.

"It all comes down to down to the total economic picture of the water: how much is it to buy fresh? How far is that in miles? How close is the nearest injection well? How far is the next well where we want to use the water?" Migyanka noted. "So, more than just brine injection well prices comes into play. It's quite a complex issue, really."

Migyanka sees increased adoption of water reuse from one fracking stage to the next, over and over, and not having to reformulate the frac fluid formulation. A biocide is used to kill the bugs in the water that cause corrosion, and water is reused four or five times instead of once before being disposed. This trend is catching on in Texas, Oklahoma, Colorado and other places of true water scarcity and drought.

He also sees high total dissolved solids fracking as the biggest factor in water recycling in the coming years.

"Initially, it was thought that the water needed to be at 25,000 to 40,000 parts per million (ppm) TDS, such as iron aluminum, calcium and sodium) but what testing and experience has shown is that they can frack a well with TDS levels as high as 285,000 ppm TDS, so that the water is pumped in the well at 25,000 ppm, flows back at 100,000 ppm, they reuse it with biocide-only treatment, they refrack at 100,000 ppm, it flows back at 150,000 ppm," said Migyanka. "They reuse it again, and so on, until they are done with that well."

Karen Boman has more than 10 years of experience covering the upstream oil and gas sector. Email Karen at kboman@rigzone.com.

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Sunday, June 23, 2013

Lukoil Targets 150,000 Barrels per Day from West Qurna-2

OAO Lukoil Holdings, Russia's largest non-state oil producer, aims to produce 150,000 barrels of oil a day at Iraq's supergiant West Qurna-2 oilfield by the end of December 2013, a company executive said Tuesday.

The 13-billion-barrel field is expected to raise output to 400,000 barrels a day by April 2014 and to hit 550,000 barrels a day in 2015, the executive told Dow Jones Newswires.

Lukoil will invest $1 billion in 2013 to start first production from the green field, located in the Basra governorate near the Iranian border, he said. Last year the company invested a similar amount, putting total investment in the field by the end of this year at $2 billion. Lukoil had said that it would invest a total of $30 billion to upgrade the field.

To date the company has drilled eight production wells and is planning to drill another 27 wells this year, he said, adding that four rigs are drilling in the field.

In January, Lukoil signed a supplementary agreement with Baghdad to reduce the project's target production and prolong its duration. The agreement also put on record the transfer to Lukoil of Statoil ASA's participation interest of 18.75% in the project.

The parties agreed to reduce the project's target production level to 1.2 million barrels a day from 1.8 million barrels a day, and to prolong the validity of the contract to 25 years from 20.

The company has increased its stake in the West Qurna-2 project in Iraq to 75%, following last year's withdrawal of Statoil. Iraq's state-owned North Oil Company owns 25%.

Operator Lukoil and Statoil were awarded the technical service contract at West Qurna-2 in December 2009.

View the original article here

Tuesday, April 2, 2013

Dart Targets Several CBM Developments in the UK

USGS: Estimate of Conventional Gas Resources Grows Internationally

Coal-bed methane (CBM) is one of a number of unconventional sources of natural gas that several countries around the world are currently exploring – particularly in the developed world where coal itself is being increasingly seen as too dirty a fuel to use and too expensive to mine from deep beneath the ground.

CBM (also known as coal seam gas) has become an important source of energy in the United States and a number of other countries. Australia, for example, has very rich deposits of CBM and its industry has expanded significantly since the beginning of this century.

Recently, a firm that has its roots in the Australian CBM industry successfully tested a CBM well in Scotland. Dart International Ltd. reported in late January that during a three-month production test at its Airth 12 well, on the PEDL 133 license, it achieved sustained gas flow rates in excess of 500,000 standard cubic feet per day and is now powering an electricity generator with the gas – making Dart the first company in Scotland to produce electricity from CBM.

In the UK, total CBM resource is estimated at 97 trillion cubic feet (2,900 billion cubic meters of gas), according to a 2004 British Geological Survey study. Although this study estimated that as little as 1 percent of this resource could be recovered – because of perceived widespread low seam permeability, low gas content, resource density and planning constraints – the UK's Department of Energy and Climate Change (DECC) points out that analogous CBM developments in the United States have been proven to achieve recovery of between 30 and 40 percent in some fields.

Consequently, DECC believes that if 10 percent of the UK's CBM resource potential could be developed it would correspond to more than three years of the country's natural gas supply.

Dart Targets Several CBM Developments in the UK

CBM extraction exploits the fact that natural gas in a coal reservoir is stored differently to how it is stored in a conventional reservoir. Instead of occupying spaces as a free gas between sand grains, the methane is held to the surface of the coal by a process called adsorption. Large numbers of micropores in the coal mean a very large surface area that methane molecules can be attached to. Indeed, due to these micropores in its structure one pound of coal typically has the equivalent surface area of a few dozen football fields.

This means that an individual lump of coal can contain a very large amount of methane. Typically, companies looking to extract methane from a coal seam judge it economical if it contains in excess of 50 cubic feet of natural gas per ton of coal.

The gas in the coal is held in place by the pressure of surrounding water and rock, so simply by drilling through a coal seam this natural gas can be pumped out.

Dart is in a good position to exploit this potential in the UK since it has acquired 40-plus onshore licenses there that enable it to conduct unconventional gas projects, said Dart Chief Commercial Officer Eytan Uliel.

The company first developed its CBM expertise in Australia and has since honed the practice at projects in China and Indonesia.

"The well design for Scotland was first developed in Australia but it was perfected at one of our projects in China and has been adapted for the geological conditions you find in Scotland," Uliel explained to Rigzone in a recent interview.

"That's really the magic of CBM. People make a big song and dance about it being a technology-driven thing, but actually the technology is vanilla. It's nothing when you compare it to offshore conventional wells. The technology is very simple. You are drilling shallow holes, you are intersecting coal mines, drilling a horizontal-section hole. It's not complicated by any means.

"The expertise you need is what you might call the diagnostic tool kit. The ability to take a particular coal system in a particular place and then figure out the right well design, the right completion architecture and then the right surface solution that creates a viable economic project."

In the immediate future, Dart is focused on its Airth development in Scotland. Rather than embark on a rapid rollout of CBM in the UK, Dart prefers to take a "slow but steady" approach.

"The lesson learnt in Australia and the lesson to be applied here is that people want to see a result and everyone is skeptical. And for good reason," said Uliel.

"A lot of [companies] have tried and a lot have failed, so the focus of this company is very much to get a project up and running, and prove to people it can be done both commercially but also viable in a community sense. You are working with local communities. People need to see that you are responsible and you create jobs and you don't damage the environment. So, we do one project and we do it well."

The Airth project was previously a joint venture between Composite Energy (since acquired by Dart) and BG Group plc. Although the companies drilled a few exploration wells, proved gas was there and it flowed, it has taken Dart's involvement to make the project it work.

"They hadn't quite figured out how to flow it sustainably, and how to maximize the production, and they hadn't quite come up with the right development plan for that license," Uliel said.

While, vertical drilling into a coal seam can – and has – yielded commercial gas at certain projects in the United States, it is horizontal drilling that has made CBM a viable source of gas in Australia and elsewhere.

"In Australia, we adapted horizontal drilling technology to CBM. So what we did was, instead of drilling a simple vertical well, what we would do was drill a vertical and then off that vertical we would drill a very long horizontal well in the coal seam. And what that does is it effectively creates a channel along which the gas can flow back to the vertical and then out to the surface.

"Now, if you've got a coal seam that's 10 meters thick and you drill a vertical well, you've got access to a 10-meter area of coal. But if you drill a horizontal well, you can drill them one, two or three thousand meters through the coal seam. And so from the same well, you are opening up a huge area of coal. You are draining a very large area and that's what made the industry work in Australia."

Uliel explained that this is what Composite and BG Group had been trying to do in Scotland.

"The problem was that the seams are so thin that even drilling one single lateral for a long way through a coal seam didn't give you enough gas volume to justify the economic cost of the well you are drilling," he said.

"So, what we've done, and this is the 'architecture' we've brought from Australia via China to Scotland, is instead of drilling one horizontal into the seam you drill four. So you have different coal seams at different depths and from the one vertical well you drill four horizontal sections.

"Each horizontal is about 2,000 meters so from the well you are accessing 8,000 meters of coal from four different seams. So there's a lot of know-how that sits with that, because the pressure at which the gas is held in each seam is different, the flow rates are different, the water rates you get are different and the knowledge you have about how to drill it and then how to operate that well."

Uliel continued explained that the production test that Dart undertook at the end of last year at Airth saw the firm take one of these wells in order to see how it would flow.

"We produced on a sustainable basis about half a million cubic feet of gas per day and we let it run for a short while and we got up to about 800,000 cubic feet. And that's a viable, economic, doable proposition," he said.

Dart expects to start selling the gas produced – up to 10 billion cubic feet per annum initial and perhaps double that over time – into the UK's national gas grid.

"There is a main trunk pipeline that runs to our license area that is owned and operated by Scottish and Southern Energy (SSE). And we have a gas sale contract agreed with them. So, as and when we we're ready to start delivering the gas, we will.

"The issue there is you need to compress [the gas] so it gets to the pressure that the pipeline can receive it. And so we're currently going through a process of planning and permitting so that we can put in the compressor facility and drill more wells. And once we've done that we'll be in a position to start delivering gas to SSE.

"In the meantime, for the early gas that we're generating from the first few wells we've drilled we have a small electricity generator on site and the gas goes into that. We manufacture electricity and we sell it into the electricity grid. So we're doing that already."

Dart is investing up to $150 million into the Airth project, and much of this will go into the local economy. The project will support between 40 and 50 local jobs as well.

Once the Airth project begins exporting gas to the grid, Dart will turn its focus onto the Canonbie project, located on onshore license PEDL 159, which straddles the England/Scotland border.

"It will be a very similar project in terms of scale, scope, size and profile to the one at PEDL 133," Uliel explained. "So there, we've done early exploration work. We've drilled some core holes. We need to know about the coal and the gas content and permeability. So the next thing we would need to do there, which is on our agenda for either this year or early next year, is to put down a couple of pilot wells and run a production test, and see how well the coal there will produce."

The Canonbie project could also produce between 10 and 20 billion cubic feet of gas per annum, according to Uliel, who pointed out that while such numbers represent a "drop in the bucket" in the context of the overall energy equation for the UK, they will also help the country reduce its dependence on imported gas.

"Every molecule of domestically-produced gas means a molecule less of Russian or Norwegian gas that needs to be purchased," he said.

"The UK is blessed with considerable shale gas resources and considerable coal-bed methane resources, and if they can be sensibly tapped over the next several years they will make a big difference to the energy dynamic here. That's for sure!"

A former engineer, Jon is an award-winning editor who has covered the technology, engineering and energy sectors since the mid-1990s. Email Jon at jmainwaring@rigzone.com.