A new technology holds promise for existing wells and so-called “stranded” production too.

By Michael J. Economides & Claudio H. Steuer

The time has come for a new era in petroleum production worldwide (particularly in the very promising but remote deepwater and/or pre-salt basins) and, as usual, a crucial component will play a pivotal role. Marine compressed natural gas (CNG) has been considered in the past, primarily as a means of transportation, but proved unattractive for long distances or large volumes when compared with liquefied natural gas (LNG). However, marine CNG still remains economically attractive over shorter voyages (up to ~4,000 km) and medium volumes, and recent advances in containment systems are poised to provide marine CNG with the best opportunity yet to emerge as a major enabler of new and previously stranded hydrocarbons by becoming an important optimization tool to petroleum well performance.

 

Almost half of offshore natural gas (SEC-type reserves) is considered “stranded” because of the high cost to harness it in remote locations and the lack of a suitable market for the gas. Most such reserves do not contain enough gas to justify their own gas-transmission or LNG solution. Furthermore, inoperable gas affects oil production in many adverse ways, from the logistics of handling and facilities’ capacity to the cost of the treatment itself. Marine CNG used as a wellhead fluid shuttling service can generate significant monetary benefits for an operator attributable directly to the new technology and its innovative application. This technology could enable a higher number of fields to become viable by simply dehydrating the wellhead gas (where carbon dioxide or sulfur are present in relevant quantities) and enabling the centralization of gas treatment plants.

 

A Revolutionary Containment System
The new technology under development has several components. The main one is the containment system, manufactured with composite materials that are far lighter than metal and yet can withstand the 200-atmosphere pressure and corrosion from hostile raw gas composition straight out of the primary separator. Gas viewed like this is no longer a midstream product in need of further processing prior to sale but a potential upstream, saleable product.

CNG cargo containment systems produced with composite materials can reduce overall steel weight by 50-80 percent and operate with pressures ranging from 150 to 250 bars, sufficient to accommodate a wide range of gas-oil-ratios (GORs) without the need of refrigeration. This enables the monetization of natural gas and well fluids straight from the primary separator.

 

The systems can operate with temperatures ranging from -60°C to +60°C, suitable for a wide range of upstream production environments. The combined use of refrigeration and pressure enables marine CNG to achieve a significantly higher energy density, approaching ~75 percent of LNG and thereby increasing the economic feasibility of transporting raw gas and associated liquids, as well as natural gas, over longer distances and in larger volumes.

 

Containment systems combining steel, refrigeration and displacement fluids with inhibitors and pH control to manage corrosion resistance can achieve similar benefits and operate at approximately 130 atmospheres and -30°C. In addition, they provide great control flexibility over pressure and temperature dynamics, minimizing hydrocarbon liquid formation during loading and unloading.

Hull and containment systems and propulsion systems continue to explore new materials and applications in an effort to lower costs. Issues involving energy absorption capacity in the unlikely event of rupture or ship stability during laden and ballast voyages still fuel divergent points of view. But the overall trend is clear: Develop new materials, technologies and applications to increase hydrocarbon production from challenging operating environments and, over time, provide greater transportation capacity for raw or saleable gas at a lower unit cost.

Benefits
In high GOR wells, an increase in gas production can affect oil production adversely. To accept the increased gas production and still fit within the design and operating envelope of the associated facilities, oil production may have to be reduced. The innovative use of marine CNG technology can complement existing production systems and enable higher oil production.

This ability to handle raw gas can be used to advantage at the bidding process. E&P companies primarily target oil discoveries. A raw gas management and transportation solution would enable increased gas production (irrespective of sulfur or CO2 composition) and be a welcome addition to the value of the upstream asset instead of a complex headache. The creative use of marine CNG in raw gas management and as a production tool becomes a value-enhancing activity in its own right.

 

Other benefits include:
• The relative ease of handling and construction of loading and offloading facilities allows reduced development time and provides flexibility in adjusting the system to changing production profiles.
• The floating nature of the production and transportation assets makes it easy to redeploy them to other locations when production volumes begin to decrease.
• Accelerated monetization of natural gas during the interim period of construction of LNG production facilities or long-distance gas transmission pipeline systems.
• Because the new-generation containment systems can handle raw gas directly from the wellhead, significant savings can be achieved by avoiding duplication of processing facilities when producing from remote fields and centralizing such facilities on large offshore platforms or on-shore.
• In case of failure, hybrid metal/composite and all-composite structures may allow leakage but will not collapse or burst, therefore avoiding gas containment explosion.
• New-generation gas containment systems are light, have higher specific properties and can weigh as much as 20 percent less than metal-based containment systems, thereby increasing transportation capacity and energy density and lowering the unit cost of transported gas.

Shuttling of raw gas is the only process to have a positive economic effect on overall production. Gas flaring and treated gas reinjection are techniques that enable sustainable oil production but at a loss of profit due to the high cost of the solution. The alternative to gas flaring is lower oil production and, in worst-case scenarios, shut-in production. With this new technology it is possible to deploy solutions in shorter time frames to complement existing production systems or form part of new production systems.

 

Potential Applications
• Enabling Higher Oil Production – Consider an offshore oil production facility with a maximum production capacity of 200,000 barrels/day with 1.5 Bcf/day (GOR 7,500 scf/stb). After three years, and unexpectedly, the producing GOR increases to 10,000 scf/stb, enabling only 150,000 barrels/day to be produced. The lack of gas-handling capacity effectively shuts in the equivalent of $1.8 billion/year in revenue. Shuttling the excess raw gas and associated liquids can increase production by 50,000 barrels/day with minimal difficulty. Benefits: $5 million/day.
• Putting a Gas-Rich Well on Production – A new well is drilled on an existing offshore platform. Although it can deliver 15,000 barrels per day, a high GOR (e.g., 10,000 scf/stb) may preclude its inclusion in production if the gas treatment facilities or the gas transmission systems are maxed out or near capacity. Benefits from wellhead-shuttling services: $1.5 million/day.
• Standardization of Production – In the future, production systems for natural gas would be standardized long before drilling, discovery, and well completions. Ordinarily, the discovery fluids would dictate the size and complexity of surface facilities such as separation processes, dehydration, and sweetening. The exact volume requirements and impurities to be treated are not known at this stage. The new technology enables the acceptance of raw gas in all cases irrespective of its composition, thereby simplifying the production and commercialization phases and saving time and money. It is not uncommon, for example, for scheduling delays, cost overruns and additional fluid-processing requirements to almost double the original budget estimate.
• Offshore Gas Gathering and Transmission System – Deepwater and pre-salt basin exploration and production are extremely capital-intensive projects. Marine CNG can provide production flexibility where gas transmission systems may be operating close to capacity and further expansion is very expensive. Marine CNG enables sustainable production (no routine flaring) from remote fields by creating a flexible and dynamic floating system where the raw gas is taken from the satellite fields to the nearest platform with gas-injection facilities or with access to gas transmission systems or taken directly to shore. It is also feasible to utilize such a “hub and spoke” configuration to connect satellite fields with an offshore floating LNG production system. This application is extremely attractive from an economic viewpoint as it enables a greater volume of oil to be produced and unlocks gas production in a technical and commercially viable manner while meeting all applicable safety and environmental requirements.
• Alternative to Submarine Sour Gas Transportation Systems – Sour gas production systems must be designed to operate with a significant safety margin to accommodate uncertainty on the gas specification over time. As such systems are costly to deploy and maintain, they are designed to handle “worst case scenarios” and be virtually maintenance-free. They normally require the use of exotic materials and expensive internal cladding and external coating. A marine CNG alternative can provide scalability and significant schedule and capital savings.

 

The Golden Era of Natural Gas
As we enter “the golden era of natural gas,” economies throughout the world will seek to enjoy the many benefits afforded by this most environmentally friendly of fuels for power generation and as a viable alternative to liquid transportation fuels. Regional natural gas markets will continue to grow in size and importance, providing E&P companies the opportunity to connect new or previously stranded reserves to growing gas markets and generating higher value for all stakeholders.

As this is an important new area of high value-added activity for E&P companies, entrepreneurial and strategically focused players are likely to seek direct or indirect control of such technologies to benefit from the competitive advantage provided. Precedents exist in the leveraging of LNG, FLNG and GTL technologies, which are far more challenging, complex and capital-intensive. Stay tuned for a new era of upstream gas development and an avalanche of new applications, which in a reasonably short period of time should provide you with an opportunity to see a marine CNG carrier coming to a field or receiving facility near you. – MarEx

Original Article

Chevron Corp. (CVX), the second-largest U.S. oil company, began extracting crude from a southern California field using steam produced by a 29-megawatt solar- thermal power plant.

BrightSource Energy Inc.’s system uses mirrors to focus sunlight on a boiler at Chevron’s Coalinga, California, enhanced oil recovery project, the solar company said in a statement after extraction began today.

Solar-thermal technology companies such as BrightSource are targeting industrial users in the oil-recovery and food- processing industries as customers as well as power generation.

Mining and metals processing are also very promising, especially in remote areas where power can also be generated along with heat, Charlie Ricker, BrightSource senior vice president of business development, said today in an interview.

The company is exploring the possibility of more plants with Chevron and others, Ricker said.

“This technology has the potential to augment gas-powered steam generation and may provide an additional resource in areas of the world where natural gas is expensive or not readily available,” Chevron Technology Ventures President Desmond King said today in a company statement. The project produces about the same amount of steam as one gas-fired steam generator, Chevron said.

7,644 Mirrors

The Coalinga plant consists of 3,822 mirror systems, or heliostats, each with two 10-foot (3-meter) by 7-foot mirrors mounted on a 6-foot steel pole focusing light on a 327-foot solar tower. Steam created by the heat is fed into the oil reservoir, making it easier to bring to the surface. The system began generating steam in August, Kristin Hunter, a spokeswoman for Oakland, California-based BrightSource, said today in an e- mail.

Areva SA’s Areva Solar, Seville, Spain-based Abengoa SA, Erlangen, Germany-based Solar Millennium AG (S2M) and Burbank, California-based eSolar Inc. are competing with BrightSource with their own solar-thermal technology.

Glasspoint Solar Inc., based in Fremont, California, makes solar steam generators for the oil and gas industry using mirrored troughs inside of glasshouse enclosures to protect the mirrors.

$16.3 Billion Market

Enhanced oil recovery, or EOR, fits very well with solar temperatures, Glasspoint Vice President John O’Donnell, said today in an interview.

Some 32 percent of California’s industrial and commercial gas use is for EOR as its use grows in the U.S. and all over the world, O’Donnell said. The state produces about 40% of its oil using EOR and in a few years that will grow to 60%, he said.

The company can produce heat for EOR for about $3 per million British thermal units, compared with about $4 for a comparable natural-gas plant in the U.S. and between $10 to $12 for other conventional solar thermal technologies, O’Donnell said. “We are the only ones below natural gas right now in the U.S.”

According to BCC Research, the global market for enhanced- oil-recovery technologies was $4.7 billion in 2009 and is expected to grow at a 5-year compound annual rate of 28 percent, reaching $16.3 billion in 2014, BrightSource said in its statement.

Original Article

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As the conventional and cheap oil and gas start to dry up in the Middle East, a bigger, even better opportunity seeks to replace it.

For many who aren’t familiar with the region, the Middle East comes across as an updated version of Lawrence’s Arabia, only with lots of oil. But this mosaic of cultures isn’t made up of only Arabs or Muslims, and most Middle East countries are neither awash with heavily armed, rather excitable citizenry… nor with black gold, which is what we’re interested in. Twenty-three countries comprise the Arab League, but only Saudi Arabia, Iraq, Kuwait, the United Arab Emirates (UAE), and Iran are major oil producers.

No matter; with the exception of Kurdistan in northern Iraq, none of the oil heavies are currently open to us investors anyway. We’re digging for other finds, with three basic criteria. We’re looking for countries in the Middle East that:

* Have potential for unconventional production, such as oil shales

* Have incentive to develop it, and

* Are either net importers of oil or soon will be.

Why? In short, conventional production is in decline, but demand for oil isn’t. That means the state-owned oil companies and large companies operating in the region either need to find new fields and basins or apply new technology to get more out of established ones. Or both, of course. Nowhere is this reality more critical than in the Middle East, the world’s most important oil region, where oil production is the lifeblood of governments.

Our analysis, gleaned from data and on-the-ground experience alike, points to investment opportunities in new, unconventional technology and resources. Exploration costs will likely be lower, as companies aren’t starting from scratch. And in what we see as early days in the national drives for energy security, it makes sense to look close around your own turf.

We believe that blue-sky potential lurks in companies operating in the Middle East with expertise in unconventional production, access to good source rock, and management that can marry the two.

The Proving Grounds

It’s still early in the game, which can mean both good (high returns) and bad (high uncertainty) for investors. We believe the potential upside of unconventional development in the Middle East is just too big to ignore, however. So what we’ve done, is track down and lay out the most likely go-to countries for those explorers with the right stuff.

The following chart will narrow further the countries that meet the three criteria we outlined above. That is, who’s “in the red” when it comes to oil?

We see here that six countries currently rely on imports for their crude oil: Egypt, Cyprus, Lebanon, Jordan, Israel, Turkey.

In addition, two countries appear on their way to becoming net importers of oil: Syria and Yemen.

Egypt

Outlook: The oil and gas industry are an essential sector in Egypt’s economy, and the country’s reserves convey its potential to become a significant producer. In 2009, Egypt produced 678,300 of barrels of oil per day, while consuming 683,000 barrels per day. Egypt has traditionally been a net producer, but production peaked in 1993 and has been in decline. Combine that with its increase in domestic consumption, and Egypt is now a net oil importer.

Consequently, the Egyptian government has reversed its previously much harsher fiscal regimes and now actively encourages the exploration of domestic oil, which has resulted in an industry dominated by foreign players.

Natural gas, on the other hand, has tripled in production in recent years due to some major discoveries. Thus Egypt is a net producer here, and more important in the broad picture, a source for European natural gas. European countries are usually eager to decrease their reliance on Gazprom, the state-controlled gas giant from Russia.

Egypt has a developed network of pipelines to export its natural gas to Southern European and eastern Mediterranean countries. It also sends liquefied natural gas (LNG) to Europe, Asia, and the Americas.

However, as natural gas represents over 80% of Egypt’s source of electricity, the government has slowed plans for export expansion to ensure all domestic demands will be met before any further moves.

Cyprus

Outlook: Cyprus has no oil or gas production currently, and so must import all it needs. However, an oil deposit has been found recently in the seabed between Cyprus and Egypt. An oil licensing round took place in 2007, when 11 blocks were offered to potential investors.

This first round took place against a backdrop of opposition from the Turkish government. As a result of this territorial dispute, companies chose not to bid, and as of now, only Noble Corporation has a production-sharing agreement (PSA) with the Cyprian government.

In May 2010, Cyprus announced it was close to commencing a second oil licensing round for several offshore blocks. It’s again under Turkish protest. Turkey has even warned Lebanon and Egypt against working out a deal with Cyprus for oil exploration.

Lebanon

Outlook: Lebanon also has neither oil or gas production at this time. However, Cyprus has signed lineation agreements with Lebanon and Egypt to exploit large hydrocarbon reserves that cross borders offshore, as we mentioned above, and hope to begin exploration by 2012.

And according to Lebanon’s parliament speaker, Nabih Berri, gas reserves found off the coast of Israel are located in Lebanon’s territorial waters as well. These fields, however, may run into developmental difficulties as Israel and Lebanon to this day still dispute their maritime borders, leaving large fields such as Leviathan and Tamar in a state of limbo.

Jordan

Outlook: Large corporations have been eyeing the unconventional potential in Jordan for quite some time, but were put off due to both political as well as economic reasons. However, with advancements in oil shale technology and a gradual shift towards liberalization by the Jordanian government, which has long been envious of the hydrocarbon wealth of its neighbors, Jordan’s government has established plans to liberate the oil market in the next five years. If that happens, it will be a first for investors since 1958. Under the National Energy Strategy’s initial phase, four companies will be offered 25% of the kingdom’s reserves. The remaining 75% will remain under the control of the state-owned Petroleum Refinery Company (JPRC) until full liberalization.

This development will pave the way to exploit Jordan’s oil shale resources. Oil shale deposits underlie more than 60% of the Kingdom of Jordan and have enormous potential. The World Energy Council estimates Jordan’s oil shale reserves at approximately 40 to 60 billion tons, making it the second richest state after Canada in rock oil reserves.

Furthermore, the oil shale quality is very high compared with the oil shale in the United States. Jordan has recently signed a deal with Shell Oil to extract oil shale in the central part of the country. First commercial quantities are expected by 2020, with an estimated amount of 50,000 barrels of oil per day.

Modest natural gas reserves were discovered in 1987, and the Risha field near the Iraq border produces approximately 30 million cubic feet of gas per day. However, production is pretty flat and looks to stay that way. That means imports.

Israel

Outlook: Israel relies on importing resources to meet the majority of its energy needs. It boasts no major reserves, and thus oil production is minimal. However, as we said above, Israel has found substantial natural gas reserves located in Mediterranean deep water. This discovery has prompted increased exploration off Israel’s coastline, not to mention increased territorial disputes.

The U.S. Geological Survey reports that Israel’s offshore reserves could hold 122 trillion cubic feet of recoverable gas. That makes it one of the world’s richest deposits.

As a result of this discovery, Lebanon has rushed through approval of a law that outlines the guidelines of surveying, exploring, and producing of gas. The legislation also calls for a sovereign wealth fund to manage the potential revenues.

Nevertheless, Lebanon is still three to four years behind the Israelis, as it still must secure investors, select bidders, and begin exploration work. Israel is already well on its way.

Turkey

Outlook: Although Turkey has both oil and natural gas reserves, the country is a net importer for both resources. It may become energy independent as new oil and natural gas reserves have been discovered off the coast of the Black Sea, Eastern Thrace, the Gulf of Iskenderun, and in the regions near the borders of Syria and Iraq.

Due to its location, Turkey is vital in energy transportation between major oil-producing areas, in the Middle East and the Caspian Sea, and consumer markets in Europe. In 2009, the pipeline network in Turkey covered over 3,636 kilometers for crude oil and 10,630 kilometers for natural gas.

One of the pipelines, the Baku-Tbilisi-Ceyhan, is the second largest oil pipeline in the world. It’s responsible for delivering crude oil from the Caspian Sea to the port of Ceyhan on Turkey’s coast. From Ceyhan, the crude oil is distributed to oil tankers, which will further transport it to the world’s markets.

Another pipeline, Nabucco, is in the planning stages. It is expected to provide European markets with natural gas from the Caspian Sea basin.

Syria

Outlook: Compared with some of its neighbors, Syria’s oil and gas production is fairly unassuming. On the other hand, Syria is the only significant producing country in the Eastern Mediterranean region. Oil production had declined, then flattened out for several years before new fields were discovered. They’re expected to bump up future production.

Syria’s known oil reserves are located mainly near the Iraq border and along the Euphrates River, while some smaller fields are located in the central part of the country. Upstream production is controlled by the state-owned Syrian Petroleum Company (SPC). The main foreign consortium which is currently producing is Al-Furate Petroleum, a joint venture made up of SOC (50%), Shell Oil (32%), and a collection of other companies.

Contracts have been awarded to Shell, in 2008, and TOTAL, earlier this year, for exploration at greater depths in existing oil fields in the Euphrates and central areas. Offshore exploration came up dry in 2007, but recently there’s been renewed interest. The SPC has commenced plans to issue tenders for the offshore blocks in the future.

Syria is also strategically important as a transit hub and will provide a larger role with the ongoing plans for pipeline network expansions in the area.

As for gas, new fields are expected to ensure that Syria’s domestic demands are met after several years of decline in production. About 35% of natural gas production is reinjected into oilfields for enhanced oil recovery techniques, with the remainder going mostly to generate electricity and for domestic use. By the end of 2010, Syria expects to double its natural gas production.

Yemen

Outlook: Like Egypt, Yemen is a strategic hub for oil shipping. More than 3.7 million barrels of oil pass daily through shipping lanes off its coast. The alternative is a very costly trip around the southern tip of Africa, so governments and oil companies are anxious to avoid any disruptions.

Hydrocarbons currently account for approximately 25% of Yemen’s GDP and over 70% of government revenues. Accordingly, the government is actively seeking to increase foreign capital in this sector.

Barring significant change, however, its harsh fiscal regime is strangling exploration. Yemen is currently a net producer of oil, but it won’t be for much longer at this rate. Production is currently limited to two major sedimentary basins, but another 10 basins are believed to hold oil reserves.

A number of companies are interested in the area of Yemen’s border with Saudi Arabia, though activity has been very limited due to a combination of limited infrastructure and continued security concerns. An initial licensing round in 2007 for offshore exploration also stirred interest, but the rise of Somali pirate activity in the Gulf of Aden has more or less put the kibosh on that. A fourth round of bidding was postponed in August 2009 because of the pirates and the exorbitant insurance rates that companies would need to pay to operate in the region.

Up until 2009, all natural gas produced was reinjected to provide enhanced oil recovery. Natural gas export only became viable when a milestone agreement was signed in 2005 with Korea Gas Corp. Yemen also signed an agreement Swiss GDF Suez Company and TOTAL. All three contracts run for 20 years.

Yemen’s first liquefied natural gas (LNG) plant, located on the port of Balhaf on the Gulf of Aden, went online in October 2009. Yemen has the ability to export over 200 million cubic feet of LNG per year, and much of the future investment into Yemen is expected to be used in the natural gas infrastructure.

What It All Means

So the question is, what do we have and, more importantly, how can we make money?

When investing in the Middle East, there’s evaluating infrastructure, fiscal policies, and, perhaps most important of all, Middle East politics.

Much of the Middle East is well developed, particularly around urban centers. But many places where a company would be looking for unconventional oil are a ways off the beaten track, and that means additional infrastructure. A prominent example is Kurdistan, where billions of dollars’ worth of infrastructure upgrades are needed to turn the region into prolific oil-producing center. A junior company alone could not possibly have the connections to build such infrastructure. Countries such as Yemen and Oman have similar stumbling blocks to investment and development. The Catch-22 is that these places are precisely where the remaining “elephant deposits” could be hiding.

Behind the scenes in the Middle East is always politics, much of it nuanced and layered by generations of history and family ties.

It takes a management team that has been in the arena before and knows the intricacies of the particular area of interest. A good security detail may be a must in some places as well.

Lastly, the fiscal systems in the Middle East are relatively tough compared with the rest of the world, and in some countries, such as Saudi Arabia, there are very few, if any, opportunities for foreign companies to even come in and share the wealth.

Countries with the highest petroleum shortfalls tend to have the lowest government take. But that’s relative. Any company that operates in the area needs to remember the Middle East holds the dubious record of the highest number of “two-stars” (80-90% government take) and “one-stars” (90%+ government take) in the world, leaving contractors with very little with which to recuperate their costs and justify their investments. Southern Iraq and Kuwait can even reach 95%+.

Who’s Got It

Nevertheless, opportunities are definitely available for those looking for them. Some are conventional, but the big upside that we see in the Middle East is in its unconventional potential. Reconnaissance and seismic data for the region are readily available due to decades of exploration in the area, saving companies millions, if not billions of dollars that would have been needed to do the same work. There are also a good number of pipelines here that, where geography and geology meet, can convey a premium to any unconventional oil production. As several countries begin to look for the oil shale opportunities, the unconventional story has the potential to be the biggest boom in the energy market in decades.

Month after month, Marin and his energy team analyze the global energy markets to find the best small-cap companies that provide vast upside potential. And with oil prices shooting up again, returns could easily match – or even surpass – the 400% and 818% gains subscribers made within the past year. Try Casey’s Energy Report now for 3 months with full money-back guarantee… details here.

Original Article

BISMARCK, N.D. (AP) — State geologists are hopeful North Dakota’s sands and clays will work as a substitute for increasingly sparse imported materials used to boost the recovery of crude.

A worldwide supply crunch of so-called proppants — ultra-hard sand grains and tiny manmade ceramic balls — has some drillers using lesser-grade particles that have cut the yield of oil wells in the Bakken and Three Forks formations in western North Dakota.

“The reality is people are sold out of everything,” said Mike Vincent, a Golden, Colo.-based engineer. “People are taking whatever they can — an extremely low quality material is being pumped into the Bakken.”

Proppants, some the size of a grain of sugar, are used in hydraulic fracturing, a process that uses pressurized fluid and chemicals to break open oil-bearing rock some two miles underground. Cracks, propped open by injected sand or ceramic materials, provide a pathway for oil to flow to the well.

Demand for proppants — pushed by high crude prices — has jumped 400 percent in the past decade, said Vincent, president of Insight Petroleum Consulting LLC, a company that specializes in improving the efficiency of hydraulic fractures.

There are only a handful of proppant manufacturers in the North America; much of what is used in the U.S. is being imported from factories in Russia, China and Brazil, industry officials say.

There are about 20 sand suppliers and 20 ceramic proppant suppliers worldwide, said Earl Freeman, a vice president of PropTesters Inc., a Houston-based proppant testing company.

Crushed walnut hulls were first used as a proppant in the 1940s, followed by hardened glass beads and sand, he said. Resin-coated sands and ceramic proppant has been used since the 1970s.

Geologists have been analyzing North Dakota’s clay and sand deposits for about two years hoping to find potential proppant material, said Fred Anderson, a geologist with the state Geological Survey in Bismarck.

“We are starting to feel a pinch based on global demand so now we have to look at other options,” Anderson said.

A Bakken well can cost about $6 million to drill, and proppant costs average about 5 percent of the well cost and are increasing, Anderson said. Ceramic proppants, which typically allow more oil to be recovered from a well because of their hardness, can cost 10 times as much as sand, he said.

Sand proppants must be uniform in grain size, extremely hard and near perfectly round, said Ed Murphy, the state geologist and director of the Geological Survey.

“We’ve certainly looked at a lot of sands that won’t work and about a dozen or so that may meet some of the criteria,” Murphy said.

Even the North Dakota’s best sand candidates likely would not be ideal for proppants in 2-mile deep formations like the Bakken and Three Forks, geologists say. Deeper formations create more pressure and can crush natural sand.

But geologists also have identified deposits of koalinitic clays that could be used as an ingredient for ceramic proppants, Murphy said. Kaolinite is used as raw material for the more than century old the Hebron Brick Co. plant in western North Dakota, he said.

A Bakken well can require more than 3 million pounds of proppant, and high-grade ceramic proppants can increase the recovery of a Bakken well by 20 to 150 percent over the natural particles, said Vincent, of Insight Petroleum Consulting.

Murphy said his agency will ask lawmakers for $50,000 to have sands and other raw materials tested for proppant applications. Results of the testing could be completed this summer, he said.

The agency would make available the results to industry, Anderson said.

“It will be up to the entrepreneurial spirit to put the puzzle pieces together,” Anderson said.

Original Article

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ScienceDaily — A research team led by the University of Bristol has used STFC’s ISIS Neutron Source to come up with a new way to treat carbon dioxide (CO2), so that it can be used in efficient and environmentally friendly methods for extracting oil. These new CO2 soluble additives can also be used to reduce the environmental damage caused by every day industrial processes such as food processing and the manufacture of electronics. The results of this work are published in the journal Langmuir.

The researchers have developed a soap-like additive for CO2 that turns it into a viable solvent for commercial-scale enhanced oil recovery to increase the amount of crude oil that can be extracted from oil fields.

“Carbon dioxide is useful in enhanced oil recovery as it is able to flow through the pores in the rock much more easily than water,” said Professor Julian Eastoe from the University of Bristol. “The additive, a surfactant, will help thicken the carbon dioxide, which is vital for this process, allowing it to flow through the rock more efficiently. There is also a useful side effect of our ability to use CO2 in this way, as in the future the process will take carbon dioxide generated by industrial activity from the atmosphere and lock it deep underground. Getting longer life out of existing oil reserves will also give more time for research into replacements into non-carbon energy sources such as solar or hydrogen.”

Minister for Science and Universities David Willetts said: “This shows what science can do for the environment. It’s why the Government has protected the science budget. In particular it shows how financing core science facilities can lead to many different projects with valuable applications.”

Liquid CO2 is increasingly being used industrially to replace common petrochemical solvents because it requires less processing and it can be easily recycled. The difficulty has been that in order to operate effectively as a solvent, carbon dioxide needs additives, many of which are in themselves, damaging to the environment. This new development by an international team including scientists from Bristol University led by Professor Julian Eastoe, from the University of Pittsburgh led by Professor Bob Enick and ISIS scientists Dr Sarah Rogers and Dr Richard Heenan provides a solution. The project has been funded by the UK Engineering and Physical Sciences Research Council (EPSRC) and the US Department of Energy to explore using high pressure CO2 to extract residual oil retained in the pores of rock.

“The quest to find a chemical capable of modifying the properties of CO2 to make it suitable for widespread use as a solvent in enhanced oil recovery has been long,” said Professor Bob Enick. “Previous advances have involved surfactants containing fluorine, which although highly soluble in CO2, are very environmentally damaging. The new additive, surfactant TC14, contains no fluorine at all and is a harmless hydrocarbon.”

CO2 offers an efficient, cheap, non-toxic, non-flammable and environmentally responsible alternative to conventional petrochemical solvents. Even water as a solvent for example, comes with its own set of problems; after being used to flush out oil from rocks it then requires cleaning before it can be used again, whereas liquid CO2 can be re-used immediately.

The paper published in the Langmuir is the first to come from Sans2d, one of seven new neutron instruments built at the ISIS second target station, a £145 million expansion to the facility completed last year. It is also one of the first to be published using data collected at the new target station.

The new additive, surfactant TC14 enables small pockets to form in the liquid CO2 called reverse micelles causing the liquid to thicken. Neutron scattering at ISIS allowed the structure of the reverse micelles to be studied in the CO2 as they formed under high pressure. The neutron instruments giving this molecular level viewpoint are often described as ‘super-microscopes’.

“Beams of neutrons are able to penetrate deep inside samples giving unique information about the location and arrangement of the micelles at a molecular level,” said ISIS scientist Dr Sarah Rogers.

“By altering the pressure in a specially constructed experimental cell, dissolved material can easily be separated and removed leaving the carbon dioxide for the next use. It would be difficult to look at this system using any other technique as the CO2 needs to be kept under high pressure. Only under the scrutiny of neutron beams can you fully reveal its actions and properties.”

“Experiments on Sans2d are particularly fast and accurate in comparison to some older neutron scattering instruments. This development of neutron instrument technology is part of what makes ISIS a world leading science facility,” said Professor Eastoe.

Original Article

Greener, cheaper, more efficient oil extraction made possible at ISIS

A research team led by the University of Bristol has used STFC’s ISIS Neutron Source to come up with a new way to treat carbon dioxide (CO2), so that it can be used in efficient and environmentally friendly methods for extracting oil. These new CO2 soluble additives can also be used to reduce the environmental damage caused by every day industrial processes such as food processing and the manufacture of electronics. The results of this work are published in the journal Langmuir.

The researchers have developed a soap-like additive for CO2 that turns it into a viable solvent for commercial-scale enhanced oil recovery to increase the amount of crude oil that can be extracted from oil fields.

“Carbon dioxide is useful in enhanced oil recovery as it is able to flow through the pores in the rock much more easily than water,” said Professor Julian Eastoe from the University of Bristol. “The additive, a surfactant, will help thicken the carbon dioxide, which is vital for this process, allowing it to flow through the rock more efficiently. There is also a useful side effect of our ability to use CO2 in this way, as in the future the process will take carbon dioxide generated by industrial activity from the atmosphere and lock it deep underground. Getting longer life out of existing oil reserves will also give more time for research into replacements into non-carbon energy sources such as solar or hydrogen.”

Minister for Science and Universities David Willetts said: “This shows what science can do for the environment. It’s why the Government has protected the science budget. In particular it shows how financing core science facilities can lead to many different projects with valuable applications.”

Liquid CO2 is increasingly being used industrially to replace common petrochemical solvents because it requires less processing and it can be easily recycled. The difficulty has been that in order to operate effectively as a solvent, carbon dioxide needs additives, many of which are in themselves, damaging to the environment. This new development by an international team including scientists from Bristol University led by Professor Julian Eastoe, from the University of Pittsburgh led by Professor Bob Enick and ISIS scientists Dr Sarah Rogers and Dr Richard Heenan provides a solution. The project has been funded by the UK Engineering and Physical Sciences Research Council (EPSRC) and the US Department of Energy to explore using high pressure CO2 to extract residual oil retained in the pores of rock.

“The quest to find a chemical capable of modifying the properties of CO2 to make it suitable for widespread use as a solvent in enhanced oil recovery has been long,” said Professor Bob Enick. “Previous advances have involved surfactants containing fluorine, which although highly soluble in CO2, are very environmentally damaging. The new additive, surfactant TC14, contains no fluorine at all and is a harmless hydrocarbon.”

CO2 offers an efficient, cheap, non-toxic, non-flammable and environmentally responsible alternative to conventional petrochemical solvents. Even water as a solvent for example, comes with its own set of problems; after being used to flush out oil from rocks it then requires cleaning before it can be used again, whereas liquid CO2 can be re-used immediately.

The paper published in the Langmuir is the first to come from Sans2d, one of seven new neutron instruments built at the ISIS second target station, a £145 million expansion to the facility completed last year. It is also one of the first to be published using data collected at the new target station.

The new additive, surfactant TC14 enables small pockets to form in the liquid CO2 called reverse micelles causing the liquid to thicken. Neutron scattering at ISIS allowed the structure of the reverse micelles to be studied in the CO2 as they formed under high pressure. The neutron instruments giving this molecular level viewpoint are often described as ‘super-microscopes’.

“Beams of neutrons are able to penetrate deep inside samples giving unique information about the location and arrangement of the micelles at a molecular level,” said ISIS scientist Dr Sarah Rogers.

“By altering the pressure in a specially constructed experimental cell, dissolved material can easily be separated and removed leaving the carbon dioxide for the next use. It would be difficult to look at this system using any other technique as the CO2 needs to be kept under high pressure. Only under the scrutiny of neutron beams can you fully reveal its actions and properties.”

“Experiments on Sans2d are particularly fast and accurate in comparison to some older neutron scattering instruments. This development of neutron instrument technology is part of what makes ISIS a world leading science facility,” said Professor Eastoe.

Original Article

Enhanced oil recovery involves pumping carbon dioxide into underground reservoirs to extract more crude than would otherwise be obtained through natural pressure. Photographer: Adam Berry/Bloomberg

Royal Dutch Shell Plc and BP Plc stand to make “serious profit” by pumping carbon dioxide from European power plants into North Sea oil fields, according to Petroleum and Renewable Energy Co.

Putting carbon dioxide into old wells may yield profits of as much as $40 a metric ton of oil in the next decade, Stewart Whiteley, managing director at the consultant known as Petrenel, said yesterday at a seminar at London’s Geological Society.

“You can start making serious profits out of this,” Whiteley said. Energy companies should look to extract extra oil out of multiple fields in the North Sea, rather than work on individual fields, he said. “It’s a matter of whoever gets there first.”

Enhanced oil recovery involves pumping carbon dioxide or other gases into underground reservoirs to extract more crude than would be obtained through natural pressure. The process has the advantage of extending the lifespan of an oil field, while permanently burying the pollutant. Carbon capture and storage has been touted as a way of slashing emissions of CO2, a greenhouse gas blamed for climate change.

“There are high capital costs to capture, transport CO2 and convert oil fields” to make them suitable for storing the greenhouse gas, Whiteley said. Using CO2 for enhanced oil recovery has the potential to make carbon capture and storage a profitable business, he said.

BP shelved a plan to use its Miller field in the North Sea for CO2 storage in 2007 after the U.K. didn’t provide the company with tax incentives for the project. Kinder Morgan Energy Partners Ltd. and Denbury Resources Inc., two pipeline operators in the U.S., are profiting on transporting and storing CO2, Whiteley said.

Petrenel estimates it would cost a polluter $7 to $20 to dispose of a metric ton of carbon dioxide underground for storage in an aquifer or depleted gas field, without the prospect of extra oil revenue. The CO2 could turn into an asset in extracting more oil instead, he said.

The figures don’t account for costs of capturing the CO2 from the source, such as power stations, just transporting and storing the gas, he said.

Original Article

BILLINGS – A new technology may help increase oil production in South-East Montana in the coming years. It’s called CO2 Enhanced Oil Recovery and was discussed at the annual Montana Petroleum Industry meeting.

The technique has never been used in Montana, but could increase production from the Bell Creek Field in Stillwater County. CO2 helps push the oil to the surface, engineers said it’s more effective than pumping the oil. The state’s oil production has been decreasing since 2006.

“Without more wells, without more explorations and production, without more applications like different kinds of secondary recovery, our oil production is going to continue to decline,” Montana Petroleum Association Executive Director Dave Galt said.

The oil and gas industry is responsible for 12,000 jobs in Montana and a total economic impact of $9 million.

Original Article