New Zealand Oil & Gas has commenced its planned seismic survey program over the near-shore area within PEP 38729, which is located in the northern Taranaki Basin.

The seismic data from this survey will provide a critical link between previously acquired onshore and offshore seismic lines to improve the structural definition of the Felix and Opito-Updip prospects, which is expected to result in the identification of a
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suitable drilling location.

The onshore and offshore seismic shots are being recorded on an 8 km long live receiver spread that spans the gap between existing onshore and offshore seismic lines.

The acquisition geometry is tailored to "undershoot" the basement overthrust, in order to better illuminate the Eocene Kapuni Group sandstone reservoirs that were intensely deformed in the Oligocene/Early Miocene convergence of the Pacific and Australian tectonic plates. Sands of the Kapuni Group formed highly prolific hydrocarbon reservoirs, as evidenced by the offshore Maui, Pohukura, and Tui fields.

Processing and integration of the new seismic data is likely to be completed around December 2006, following which a decision to drill an exploration well will be made in early 2007.

Worldwide offshore rig utilization dipped slightly this week, as a net total of two rigs came of contract pushing utilization down to 84.3%.

Rig utilization impacts the distribution of the rig fleet around the globe. As demand grows in one area, it may decline in another and rigs move to new markets. This week, we'll examine where rigs have been moving over the course of the last 6 years.

Moving On Up
All around the world, rigs are moving into developing regions, pushing the offshore rig counts higher than they have ever been in these areas.

Mexico has seen the largest increase in the number of rigs working its waters. In July 2000, there were only 5 rigs offshore Mexico, 4 of which were under contract. That number fluctuated somewhat through 2001 and into 2002, when the rig count began to take off. At the start of 2002, there were 10 rigs in Mexico and by the end of 2002 there were 26 rigs, a 160% increase in 1 year. The growth continued as Pemex increased its exploration budget on into 2004, when the Mexican rig count peaked at 45 rigs and held at that level for 10 months. From the initial level of just 5 rigs to 45 rigs is an increase of 40 rigs, an 800% increase. Since the start of 2005, the rig count has fallen back to a current count of 37 rigs.

The Persian Gulf has been another area that has benefited from a growing rig fleet over the last 6 years. In July 2000, there were 44 rigs in the region, working at just 66% utilization. That number started to grow in early 2001, and since that time, a total of 28 rigs have moved into the region pushing the overall rig count up to a current total of 72 rigs. That's an increase of 28 rigs, which equals 64% growth over 6 years. That growth was fairly steady over that time frame, although there was a large growth spurt of about 10 rigs in 2001 and another spurt of 8 new rigs over the last year.

In the Far East and Australia, there has been a slow and steady growth in the rig count, with an average of 4 to 5 new rigs entering the region each year. In July 2000, there were 59 rigs in the area, of which 47 were contracted. By July 2005, 18 new rigs had entered the market. But within the last 12 months alone, a total of 10 more new rigs have come into the area, pushing the total rig count up to 87 rigs. That marks a 47% increase over the last six years.

Southern Asia, for which India accounts for almost all offshore activity, has seen significant growth in its rig count since July of 2000. At that time, there were only 12 offshore rigs working in the region. That number grew steadily over the next 5 years to a peak of 38 rigs working at 100% utilization in early 2005. Since that time, the number has come down slightly and held near the mid-30s, with a current rig count of 36 rigs. That is a 200% increase caused by 24 new rigs entering the region over 6 years.

The Mediterranean, Black Sea, and Red Sea taken as a group have also seen their overall rig count increase over the last six years. In July of 2000, there were 21 rigs working in these waters, which declined to just 20 rigs in 2001. From 2001, the number of rigs in the region has grew steadily until the end of 2005, when the rig count peaked at 36 rigs with 90% utilization. In the last 7 months, the number of rigs has fallen to 31 rigs. But, for the last 6 years, the region shows a net gain of 10 rigs, a 48% increase.

Steady as They Go
A few regions of the world have had fairly consitent rig counts over the course of the last six years. Of course, none of these regions was perfectly static, but overall, the rig counts did not vary more than about 10 percent from the 6 year average number of rigs.

South America has remained steady for most of the last 6 years. During late 2000 and early 2001, the rig count varied from 40 rigs up to 57 rigs. The rig count slowly declined over the course of 2002 and 2003, steadying at about 50 rigs, which the rig count has remained near until the last 18 months, when it declined by a few more rigs to its current count of 47 rigs. With the decline in overall rig count, South American rig utilization has pushed upwards above 90% for the first time in the last 6 years, holding about 90% for the last 10 months.

West Africa has also held a consitent rig fleet over most of the last 6 years. The rig count stood at 40 rigs, of which 32 were contracted, in July 2000. By early 2001 that number had grown 12% to 45 rigs. Since that time, the number of rigs in the region has remained between 42 and 52 rigs, varying only about 5% from the average of 45 rigs. There are currently 48 rigs in the region, and 47 of those are contracted, for a very high utilization rate of 97%.

Emptying Out
With quite a few regions experiencing significant growth in the size of their offshore rig fleets, most of those rigs had to come from some other region. At the same time, not all of the rigs moving into these growing areas were rigs moving from other patrs of the world; a portion of the additions in these regions were newbuilds, which accounted for 24 new jackups, 18 new semisubs, and 5 new drillships that joined the fleet from July 2000 to today.

The North Sea rig fleet has seen a small decline in its overall size over the last 6 years. In July 2000, there were 80 rigs in the North Sea. By late 2001, that number had grown to 87 rigs. After the start of 2002, the fleet size dropped by 18 rigs to just 69 rigs in September 2004. It has since begun to recover, and the North Sea fleet now stands at 77 rigs. Overall, that is just 4% (3 rigs) below its level of 6 years ago and 12% (10 rigs) below its 2001 peak.

The Gulf of Mexico experienced by far the biggest loss in total fleet size over the last 6 years. Like the North Sea, the region experienced some growth and peaked in 2001, rising from 193 rigs July 2000 to a maximum of 206 rigs in September 2001. In the nearly 5 years since that time, the Gulf of Mexico has lost an average of more than 1 rig per month every month. The only exception to this trend was the 9 month period from January to September 2005, when the decline stopped near 150 rigs and pulled back up to 158 rigs before continuing its decline to just 140 rigs today. Over the last 5 years, the GOM has lost 64 rigs, more than 30% of its overall fleet of jackups, semis and drillships.

Used in previous centuries for tasks ranging from waterproofing canoes to paving roads, the abundant bitumen found in Alberta's Athabasca Oil Sands may serve another purpose: securing Canada's role as an important oil producer for generations to come.

Bigger than the Sunshine State
Athabasca is the largest of three designated oil sands areas (OSAs) in the northern half of the province. The other OSAs in Alberta include Cold Lake and Peace River. Together, the OSAs are believed to hold 1.7 trillion barrels of bitumen in place (oil sands are mixtures of bitumen, water, sand, and clay). The so-called "Carbonate Triangle" of the Athabasca, Cold Lake, and Peace River OSAs cover an approximately 54,400-square-mile area—slightly larger than the state of Florida.

The Alberta Energy and Utilities Board (EUB) considers 174 billion barrels of the bitumen proved reserves, which can be recovered with current technology and under present and expected economic conditions. The EUB also reckons that an additional 315 billion barrels could be recovered given the right technological advances.

Earlier this decade, one source of reserves data—the Oil & Gas Journal—began including the oil sands in its estimate of Canada's proved reserves. Though not universally accepted, this action propelled Canada's proved reserves from less than 5 billion barrels to approximately 179 billion barrels. Because the EUB, Natural Resources Canada, and Canada's National Energy Board accept this figure, the remainder of this article will use the OGJ estimates. Based on these assumptions, Canada has the world's second-largest proved crude reserves after Saudi Arabia, which reports reserves of roughly 260 billion barrels.

Holding its own
Although an exceptionally large share of its proved reserves consists of non-conventional oil, Canada is now recognized by many observers as having more crude than 10 of the 11 individual members of the Organization of Petroleum Exporting Countries (OPEC). In addition, Canada holds some 46 percent of the world's non-OPEC proved reserves.

The vast majority of Canada's oil reserves are in Alberta. Viewing a graph comparing Alberta's conventional oil reserves against its non-conventional oil sands reserves, one can appreciate the extent of the province's abundance of crude bitumen. Note that the initial volume in place is the volume of crude oil or bitumen that is interpreted to exist before any production commences. Looking at the chart below, one may conclude that a total of 489 billion barrels of bitumen could conceivably be recovered with current and future technologies. To put the magnitude of this figure in perspective, consider that the U.S. produced 192.3 billion barrels of oil from 1859 through 2005. Or to put the comparison another way, 489 billion barrels is just 3 percent less then the entire combined reserves of Saudi Arabia, Iran and Iraq, which have the world's three largest reserve bases beside Canada.

Four Decades of Growth
Commercial production of Alberta's oil sands began in 1967 when the precursor to Suncor launched the Great Canadian Oil Sands plant, which is located in the northeastern city of Fort McMurray in the Athabasca Oil Sands region. Syncrude opened the second major facility in the region in 1978. Other major players in the Carbonate Triangle include Imperial Oil, Shell Canada, ConocoPhillips, and China National Petroleum Corp. Since 1967, approximately 4.6 billion barrels of the non-conventional resource have been produced (either as crude bitumen or upgraded synthetic crude)—a mere 2.6 percent of proved reserves. Much of the growth in oil sands production has occurred since the beginning of this decade, as the chart below illustrates.

Out of the world's major oil sand deposits, only Athabasca contains reserves shallow enough to be extracted by open-pit (surface) mining. The mineable oil sands, however, represent only 20 percent of Alberta's total recoverable bitumen deposits. The remaining 80 percent lie deep below the earth's surface. Hence they must be recovered with in situ methods. (In situ is Latin for "in place."). In situ techniques remove oil from oil sands without removing the sand from the ground.

Developing economical in situ recovery methods is crucial to helping Alberta's oil sands industry evolve. There is no "one-size-fits-all" in situ process because the characteristics of bitumen in a single deposit, let alone multiple deposits, are not uniform. Despite this variation, all in situ techniques must achieve two outcomes: lower the bitumen's viscosity so that it will flow and actually make it recoverable. Presently, the two most common commercial situ methods applied by Canada's heavy oil producers are Steam Assisted Gravity Drainage (SAGD) and Cyclic Steam Stimulation (CSS).

SAGD entails drilling two parallel horizontal wells through the oil sands formation. The upper well is used to inject steam into the reservoir. The steam heats the sand and makes the oil less viscous. The more freely flowing oil flows through a slotted liner into the lower production well, which pumps the oil to the surface. Water is then injected into the area from which the bitumen has been drained.

In CSS, steam is injected into an oil sand formation before the actual pumping begins. The steam saturates and thus softens the sand, and the water vapor aids in separating the bitumen from the sand. In addition, the relatively high pressure of the underground environment leads to the formation of cracks. These cracks help to push the bitumen toward producing wells. During production, the bitumen flows to the surface on its own or is pumped up the well. When production rates begin to decline, steam is reinjected and the process is repeated.

Another in situ method is the Vapor Extraction Process (VAPEX) method, which has not been deployed commercially to date. Similar to SAGD, VAPEX uses vaporized solvents—such as ethane or propane—rather than steam. Injecting solvent into the oil sands forms a vapor-chamber. Thanks to gravity drainage, oil flows through the chamber. VAPEX is suitable for paired horizontal wells, single horizontal wells, or a combination of vertical and horizontal wells. According to Petro-Canada, which is spearheading VAPEX's development, the method is still in the pilot stage.

More Growth Ahead
News accounts about Alberta's current oil sands boom typically portray Fort McMurray as a once-sleepy little town that now finds itself in the sights of majors from as far away as China. Tracking the growth of the oil sands industry, Fort McMurray's population has risen from roughly 2,700 in 1967 to more than 60,000 today. Increased production from the oil sands should continue to play an important role in the economic development of Fort McMurray—and Alberta in general—for the foreseeable future. Based on the projected increase of oil sands production in Western Canada—to approximately 3.5 million b/d and rising by 2015—in the chart below, Fort McMurray should retain its status as a boomtown for years to come.

According to a Canadian Energy Research Institute analysis, an estimated CDN$77.4 billion (US$70 billion) will be devoted to capital spending on oil sands projects in the period 2004 to 2020. Investment is expected to grow through 2010 and begin tapering off through the next decade as projects go onstream.

Although the prospects for developing Alberta's OSAs are promising, the industry will need to continue to address a number of associated challenges. Major hurdles to overcome include an ongoing shortage of qualified labor and the continual need to refine in situ recovery techniques and reduce recovery costs. Moreover, it is important to recognize that Alberta's Oil Sands—vast as they may be—will not be the panacea for increasing global oil demand. In fact, an official with the Alberta Energy Research Institute said that even aggressive development of the OSAs is expected to supply only 10 to 15 percent of new global oil demand.

Despite the challenges that remain, the record of Albertans in dealing with the thick, gooey black stuff so abundant in their province inspires optimism. After all, they have developed world-class expertise in turning what was once just natural caulk into an increasingly desirable energy source.

Brazil is set to achieve energy self-sufficiency this year, thanks in large part to its production of heavy oil. Most of its crude oil production is offshore in the Campos, Espírito Santo, and Santos basins in deep and ultra-deep waters, and the majority of oil in these basins is heavy. In fact, heavy oil constitutes nearly one-half of Brazil's proved oil reserves of 13 billion barrels, as the chart below illustrates.

Note that the proved reserves estimate of 13 billion barrels of oil equivalent reflects the Society of Petroleum Engineers' definition for evaluating reserves. Another commonly cited figure for Brazil's reserves is 10.6 billion barrels, which stems from the U.S. Securities and Exchange Commission reserves assessment criteria.

Production history
Although oil was first discovered in Brazil in 1939, the country's oil industry experienced much of its growth after Petrobras' formation in the early 1950s. In fact, the company did not launch its offshore exploration and production activities until 1968. Also, the country's daily production rates began to rise dramatically only within the past decade as deepwater and ultra-deepwater offshore projects have gone onstream.

As the graph below shows, Brazil has made great strides in increasing its oil production to meet the country's consistent demand growth during the past decade. As the graph also suggests, the country has traditionally relied on imports to augment its inadequate domestic supply. The gap between domestic production and consumption has shrunk markedly, though - particularly after Brazil privatized its oil sector in 1997. Though no longer a monopoly, Petrobras is still by far the major player in the Brazilian oil industry - the company controls more than 95 percent of the country's production. Still partially owned by the government, the company has asserted its right to exploit most of the promising fields in the first licensing round.

A long-standing goal of Petrobras has been to help Brazil achieve petroleum self-sufficiency. That goal was finally achieved in April of 2006, when Petrobras started production from the Albacora Leste field in the Campos Basin. At full capacity, the P-50 floating production storage and offloading (FPSO) vessel will produce 180,000 barrels per day (b/d) of 19^° API heavy crude oil, bringing the country's production to an average 1.9 million b/d. By 2010, Petrobras expects to produce 2.3 million barrels of oil per day. The country's oil consumption, meanwhile, is expected to grow at an average rate of 2.6 percent per year through 2010 - when consumption should reach slightly more than 2 million barrels per day.

Recovery, development, and refining
Brazil is encouraging the use of modified FPSOs to develop its heavy oil. For instance, the dynamically positioned Seillean FPSO was upgraded to handle heavy crude in very deep water for the Jubarte field in 2002 and was later used to test and produce an extended well. Another FPSO, the P-34, was used as an early production system for this field and has now been modified to separate and treat 60,0000 b/d.

The country is also pursuing technologies to improve heavy oil recovery. According to the Society of Petroleum Engineers (SPE), costs for using a horizontal well may exceed two or three times that of a vertical well, but actual recovery can be 15 or 20 times greater. Brazil is working on a long horizontal well with sand production management technology for wells in easily pulverized rocks. The multilateral well is expected to save time and money, but it remains a risky alternative.

Because heavy oil development poses several challenges from discovery to refinement, Petrobras' Cenpes research and development center launched the PROPES program to improve heavy oil production. The PROPES team will upgrade current FPSOs, heat management and separation systems, multilateral wells, horizontal wells, and artificial lift systems. In addition, the researchers plan to develop compact separation systems for existing production facilities because the weight and limited space on offshore production units complicate heavy oil production offshore.

The PROPES team is looking to upgrade existing artificial lift technologies for viscous oils in high-flow wells . This method is used to increase reservoir pressure during oil production when the pressure begins to drop. It can be in the form of a pump or a gas injected through gas-lift valves.

On the refining front, Brazil's 13 oil refineries can process approximately 1.9 million b/d, but they have traditionally focused on lighter crudes. To compensate for their limited capacity to handle the heavier crudes that have become more prominent in the past decade, Brazilian refiners have had to swap heavy crude for lighter imported crudes. Petrobras, which owns 11 of the country's refineries, is working to keep more Brazilian heavy crude processed domestically. The company has embarked on an $11.4-billion program to double its heavy oil refining capacity, improve oil product quality, and make related safety and environmental upgrades. A significant feature of this program is a $2.5-billion heavy oil refinery that Petrobras is building in northeastern Brazil with Petróleos de Venezuela. When completed, the facility will be able to process from 150,000 to 250,000 b/d.

A rewarding strategy for Brazil?
Petrobras will invest $8.51 billion in exploration and production activities in 2006, while several foreign companies are expected to invest a total of $6.4 billion through 2007 to fulfill contractual obligations. Petrobras expects to add 2.1 million b/d of installed oil production capacity in the Campos and Espírito Santo basins through 2008 alone. The company's plans are not limited to existing discoveries, however. Out of the $34.1 billion it intends to spend on worldwide exploration and production from 2006 through 2010, $28 billion is earmarked for projects in Brazil. As the graph below shows, 59 percent of the 317 domestic exploratory wells set to be drilled during this time frame will be located in the heavy oil-rich Campos, Espírito Santo, and Santos basins.

With its eagerness to find and extract heavy oil in what are largely frontier areas, along with its willingness to enhance its domestic heavy oil refining capacity, Petrobras is clearly bullish about the non-conventional resource. Whether this aggressive approach will help Brazil sustain its much-heralded petroleum self-sufficiency remains to be seen, but the ongoing changes in the country's oil industry will be interesting to watch.

Recovery
Some heavy oil production can be accomplished via conventional methods, such as vertical wells, pumps, and pressure maintenance, but these methods are considered highly inefficient. Other technologies being used to recover heavy oil include, but are not limited to: cold heavy oil production with sand (CHOPS), vapor extraction (VAPEX), and thermal in situ methods. The main oil-related challenges involved in production are gravity and the viscosity of heavy oil.

The CHOPS method allows sand into the wellbore with the oil to improve well productivity. Wells that formerly produced only 20 barrels/day have been observed to produce more than 200 barrels/day, according to Canada's Centre for Energy, with free movement of sand into the wellbore. This technology was pioneered in Canada.

A non-thermal recovery method that involves injecting vaporized solvents into heavy oil, VAPEX creates a vapor-chamber that oil flows through due to gravity drainage. It has the potential to lower greenhouse gas emissions and significantly reduce water consumption, compared to other technologies currently in use, and can be used to recover bitumen from zones too thin for traditional thermal recovery.

Steam-assisted gravity drainage (SAGD) is a thermal in situ recovery method that involves drilling two horizontal wells, one above the other. Steam is continuously injected through the upper wellbore, softening bitumen so that it drains into the lower wellbore and is pumped to the surface. Pairs of parallel horizontal wells, one for steam and one for production, make it possible to recover bitumen continuously from oil sands.

Cyclic steam stimulation, also a thermal in situ recovery method, is a three-stage process involving several weeks of steam injection, followed by several weeks of "soaking," followed by a production phase where the oil is produced by the same wells in which the steam was injected. As production declines, the injection phase is restarted. The high-pressure steam not only makes the oil more mobile, but also creates cracks and channels through which the oil can flow to the wellbore.

Processing
Heavy oil and bitumen consist of large hydrocarbon molecules, which contain proportionately more carbon atoms than hydrogen atoms. Upgrading processes add hydrogen atoms and/or remove carbon atoms to convert bitumen into a product similar to conventional light crude oil.

Upgrading is usually a two-part process, as explained by Canada's Centre for Energy. In the first stage, bitumen is heated and hydrogen added under high pressure to break the large hydrocarbon molecules into simpler, smaller compounds. This process is known as "hydrocracking." Some upgraders also use a "coking" process to remove carbon from the bitumen to produce lighter hydrocarbons and coke (a carbon material that resembles finely ground asphalt). During the second stage, hydrogen is added to the hydrocarbon compounds to stabilize them and remove impurities such as sulfur. This process is called "hydrotreating."

Upgrading results in three main products: naphtha, kerosene, and gas oil (a fuel oil somewhat heavier than kerosene). These can be sold separately or blended to produce synthetic crude oil for sale to refineries.

Exploration
Heavy oils are frequently found at the margins of geologic basins, according to the USGS, and are assumed to be residue from formerly light oil that has lost its light molecular weight components through degradation by bacteria, water flowing through it, and evaporation.

One of the most common methods of locating heavy oil and oil sand deposits is automated 2-D electrical imaging, which plots electrical conductivity variations in the earth. Resulting geo-electrical sections can be interpreted as geological cross sections. This technique is cost-effective for exploration because oil sands are highly resistive.

Reserves
Heavy oils are found around the world, with an estimated 69 percent of the world's technically recoverable heavy oil and 82 percent of the technically recoverable natural bitumen located in the Western Hemisphere. The Eastern Hemisphere, however, contains an estimated 85 percent of the world's light oil reserves.

Reserves are often labeled "technically recoverable" or "non-technically recoverable." This just means that technically recoverable reserves are known or estimated to exist and technologies exist to recover them. Non-technically recoverable heavy oils are those that are known to exist but require more advanced technologies to remove the oil than currently exist.

Among the more notable heavy oil reserves are: Venezuela's Orinoco Heavy Oil Belt; Canada's Athabasca Oil Sands; Russia's Volga-Ural Basin; Brazil's offshore Campos Basin; Alaska's Prudhoe Bay; and China’s Luda field in Bohai Bay.

The largest known extra-heavy oil accumulation is Venezuela's Orinoco heavy oil belt, reports the USGS. The reserve boasts 90 percent of the world's extra-heavy oil when measured on an in-place basis. The Canadian province of Alberta contains 81 percent of the world’s known recoverable bitumen. The two countries’ reserves account for approximately 3.6 trillion barrels of heavy oil and bitumen in place.

Of the 35 billion barrels of heavy oil estimated to be technically recoverable in North America, the USGS estimates that approximately 7.7 billion barrels are assigned to known producing accumulations in the Lower 48 States, and 7 billion barrels are assigned to the North Slope of Alaska.

What is heavy oil?
As defined by the U.S. Geological Survey (USGS), heavy oil is a type of crude oil characterized by an asphaltic, dense, viscous nature (similar to molasses), and its asphaltene (very large molecules incorporating roughly 90 percent of the sulfur and metals in the oil) content. It also contains impurities such as waxes and carbon residue that must be removed before being refined. Although variously defined, the upper limit for heavy oil is 22^° API gravity with a viscosity of 100 cp (centipoise).

The American Petroleum Institute's "API gravity" is a standard to express the specific weight of oils, computed as (141.5/sp g) – 131.5, where sp is the specific gravity of the oil at 60 degrees Fahrenheit. The lower the specific gravity value, the higher the API gravity will be.

	Light oil	Also known as "conventional oil," light oil has an API gravity of at least 22° and a viscosity less than 100 centipoise (cp).
	Heavy oil	Asphaltic, dense (low API gravity), and viscous oil that is chemically characterized by its content of asphaltenes (very large molecules incorporating most of the sulfur and perhaps 90% of the metals in the oil). Although variously defined, the upper limit for heavy oils has been set at 22°API gravity and a viscosity of less than 100 cP.
	Extra-heavy oil	The portion of heavy oil having an API gravity of less than 10°.
	Natural bitumen	Also known as "oil sands," bitumen shares the attributes of heavy oil but is even more dense and viscous. Natural bitumen has a viscosity greater than 10,000 cP.

In comparison with heavy oil, light or "conventional" oil flows naturally and can be pumped without being heated or diluted. Light oil is characterized by an API gravity of at least 22^°, and extra-heavy oil has an API gravity of less than 10^°. Natural bitumen, also known as oil sands, shares the characteristics of heavy oil but is even more dense and viscous - with a viscosity greater than 10,000 cP.

Heavy oils typically are not recoverable in their natural state through a well or by ordinary production methods. Most require heat or dilution to flow into a well or through a pipeline.

Formation of heavy oils
The formation of heavy oil and bitumen, like other forms of petroleum, originated with plant life millions of years ago. When the plants and small organisms (plankton) that fed on them died off, the sediments containing their remains were buried at the bottom of inland seas. In a highly simplified explanation, over time, the heat and pressure converted the carbohydrates into hydrocarbons.

Oil formation usually takes place in very fine-grained sedimentary rocks known as black shales. After oil is formed, continued pressure from overlying rocks causes it to migrate through permeable rock layers until it becomes trapped in reservoirs of porous rocks such as sandstone or limestone.

Success with heavy oil depends as much on understanding the fluid properties of the reservoir as it does on knowing the geology of the reservoir itself. The reason is that the chemical differences between heavy oil and conventional oil ultimately affect their viscosity. Viscosity, in turn, influences every other aspect of a heavy oil development. Technology that was developed for conventional plays does not address the issues of producing heavy oil. Viscosity is the key.

By Shawn Taylor - Success with heavy oil depends as much on understanding the fluid properties of the reservoir as it does on knowing the geology of the reservoir itself.

The reason is that the chemical differences between heavy oil and conventional oil ultimately affect their viscosity. Viscosity, in turn, influences every other aspect of a heavy oil development. Technology that was developed for conventional plays does not address the issues of producing heavy oil. Viscosity is the key.

Every new heavy oil development eventually requires some form of enhanced oil recovery (EOR), which generally means steam, solvents or a combination of both. Without EOR, the recovery factor from what the industry calls “cold” production might be as little as one percent and no more than 10 percent. With thermal recovery, typical rates run from 30 to 70 percent. In thermal processes, however, the cost of generating the steam is typically the single greatest operating expense.

Thermal recovery options in some reservoirs include the use of cyclical steam (“huff 'n' puff”), downhole heaters, or a relatively new commercial process called Steam Assisted Gravity Drainage (SAGD). Other techniques, such as injecting slugs of water alternating with gas (WAG) are less efficient than thermal recovery, but also less expensive.


Sampling fluid properties



The mobility of reservoir fluids influences recovery rates, but the enhanced oil recovery and artificial lift methods needed to produce them changes the already complex fluid characteristics of heavy oil.

pvt To properly specify the field’s surface and downhole equipment, it is important to understand those fluid properties and how they might change throughout the system. In Alaska’s West Sak and Schrader Bluff formations, for example, heavy oil viscosities range from about 30 to 3,000 centipoise.

Determining the true viscosity of heavy oil is a complex process involving both in situ testing with wireline tools, and the laboratory analysis of fluid and core samples taken from the well. These are common procedures in reservoirs with lighter crude, but with heavy oil, even the physical task of drawing the viscous fluid into a sample container can be difficult.

Getting a representative open-hole fluid sample can take more than a full day of rig time because the first fluids to come up will be thick with drilling mud, sand, water and other contaminants. The fluid properties of new wells may continue to change over weeks or months.

Foaming oil

Foaming complicates the process even more. When heavy oil contains associated gas, foaming may occur at any point in the reservoir, wellbore, flowlines or production equipment at the surface. It happens when gas reaches its bubble point and comes out of suspension as the pressure and temperature of the fluids change.

Gas separates from lighter crudes much faster and more predictably than it does from heavy oil. The ability of the oil to foam depends on its viscosity, so higher viscosity oil is more likely to foam, and the foam it makes will be longer lasting.

While foaming can be a problem, it can also work in the operator’s favor. Since any foam that forms in the reservoir increases pressure, it can serve as a temporary gas drive, pushing oil toward the wellbore.

The trick, of course, is to understand enough about the fluid properties to know where and when the foaming is likely to occur. It won’t help you much if the foaming does not begin until fluids reach the production separator.

Fluid samples that contain oil-based drilling mud (OBM) can alter a fluid’s bubble point and viscosity. If the true bubble point is 2,000 psi, for example, OBM in the fluid sample might drop the measured bubble point to 1,000 psi. If surface equipment is then designed based on the 1000 psi value, however, operators could be surprised by gas coming out of suspension much sooner than than expected, and their facilities would not have enough capacity to handle it.

Testing also shows how the well fluids will react when mixed with other fluids, such as gas, solvents or lighter crude. The emulsions formed in heavy oil are harder to break than they are with less viscous fluids.

The danger of not doing enough fluid testing is that the design of the field’s surface production equipment will not be adequate to handle the flow.

There is no place else like the Faja, Venezuela's heavy oil belt that runs east to west, half way across the country along the lush Orinoco River valley. The Faja holds more than one trillion barrels of oil. Developing the resource is making the region a focus for new technology and turning Venezuela into the world's largest producer of heavy oil.

Outside the Faja, Venezuela has 80 billion barrels of proven crude reserves, and currently estimates that producers in the Faja can extract at least 237 billion barrels of the extra heavy crude with existing technology. With nearly 320 billion barrels of recoverable oil, Venezuela will become the world's largest holder of petroleum reserves.

The Faja's crude is what producers call extra-heavy. Oil from this tar belt averages about 8.5 API gravity, which means that it is heavier than water and oozes rather than flows. This type of oil is difficult to produce and transport, and few refineries in the world will take it. But producers in Venezuela have plenty of experience with heavy oil, and their success so far has been world-class.

In the 1990s, the Faja was divided into four major regions, each being developed through joint ventures with major international oil companies and PDVSA. A fifth major project includes China’s national oil company, CNPC, in a joint venture that converts some of Venezuela's heavy crude into a patented oil-water emulsion that can be used as burner fuel for power generation. The fuel, called Orimulsion, is produced from a recently expanded plant in eastern Venezuela.

Most of the crude from the Faja is upgraded in Venezuela to anywhere from 16 to 32 API gravity. PDVSA owns enough capacity to refine 1 million barrels of oil a day in the United States, and 3.2 million barrels worldwide.

Performance of cold production
Until now, nearly all of the Faja production has been through "cold heavy oil production with sand" (CHOPS). None of the major development projects use heat, although some inject a readily available diluent to thin the high viscosity oil.

Using CHOPS alone, Venezuela now produces about 625,000 barrels a day from the Faja, and the economics are good. The lifting costs of heavy oil production have dropped 70 percent since 1991, to just under one dollar per barrel today. The average well produces about 850 barrels a day on cold production, which is remarkable considering that at room temperature, the oil is as thick as peanut butter.

While economical, cold production alone recovers less than 10 percent of the oil in place. The government of Venezuela has now set recovery targets of more than 20 percent for all new heavy oil projects, which means that producers will be moving quickly to deploy current and emerging technology in a region rich in extra heavy oil.

The first step is to determine just how much oil is there, and where it is concentrated. In November 2005, Venezuela divided its original four major oil regions of the Faja into 27 blocks and began Magna Reserva, a project to quantify and certify its reserves to the international community. Geologic studies are underway now to identify the best places for new development.

Many oil companies worldwide are participating in this quantification and certification process, most with the understanding that they will be given a opportunity to share in the development from the regions they evaluate.

Changes in the Faja development plan have opened the door for new players. Many of these new faces belong to other National Oil Companies. These include ONGC from India, The Iranian PetroPars,Gazprom and Lukoil from Russia. There is also increased presence from current energy partners; Petrobras, Repsol and CNPC.

Testing new technology
PDVSA's goal is to boost its Faja production to 1.2 million barrels a day, and the country's total production to 5.8 million barrels a day by 2012. To reach that goal, producers are focusing on a range of new technologies, particularly in the Faja.

Since most cold production wells cannot handle thermal production, most of the advanced technology will be deployed in new development projects, after the current quantification and certification process is complete. The Faja may possibly overshadow Canada to become the world's center of excellence for heavy oil production.

Technology will be developed specifically for the Faja that is not available today. Improved seismic interpretation of the Faja sands, more efficient well placement techniques through better thermal simulation and increased reliability of artificial lift methodologies are just a few of the future areas of focus for Faja technology development One of the most anticipated new techniques is a process to upgrade the heavy oil downhole. In-situ processing would be much less expensive than transporting the heavy crude itself to upgraders or refineries.

Many observers believe that, given the excellent results from the Faja using cold production alone, the addition of thermal recovery and a host of new technologies will create the next big leap in Venezuela’s bright energy future.

Around the globe, some of the most prolific basins, such as Mexico's Cantarell oilfield, are reaching or already into maturity and have begun to experience reduced production rates. What large conventional oilfields remain lie mostly in the lands of Middle Eastern, OPEC nations. At the same time, the world's demand for oil continues to grow every year, fueled in part by the rapidly growing economies of China and India. This declining availability of conventional oil combined with rising demand has driven up oil prices and put more pressure on the search for alternate energy sources.

Into the picture come the tremendous deposits of heavy oil and bitumen that are found in the Western hemisphere. These non-conventional resources are more difficult and costly to extract, so they have barely been touched in the past. However, between the nearly 500 billion barrels of recoverable Canadian oil sands and the more than 200 billion barrels of recoverable Venezuelan heavy oil, the world could soon have access to oil sources almost equivalent to those of the Middle East.

"Heavy oils are emerging in importance as our technology in producing them continues to develop," explains Bill Bush, spokesman for the American Petroleum Institute (API). "Heavy oils, oil sands, and potentially shale, could contribute substantially to future U.S. and world oil supplies."

With the price of oil reaching new highs in 2005 and 2006, investments in these more challenging oil deposits are rapidly accelarating. In fact, the U.S. oil industry alone has invested $86 billion in "frontier hydrocarbons" since 2000, developing technologies to recover and convert inferior grades of oil, such as heavy oil and bitumen, into a more usable form for refineries, and to turn waste and residue hydrocarbons into high-value products.

The worldwide importance of heavy oils will continue to emerge as the price of oil remains high and the demand for it remains strong. For example, the tight worldwide oil supply is expected to continue to force crude prices higher and turn Canada's oil sands into the single largest contributor to net new global supply by the end of the decade, according to CIBC World Markets.

"All of the net increase in oil production this year is expected to come from non-conventional sources," says Jeff Rubin, chief economist at CIBC World Markets. "While deepwater oil is the primary source today, we forecast that the Canadian oil sands will become the single largest contributor to incremental global supply by 2010."

With oil prices averaging more than US$70 per barrel in 2006 and limited market access to OPEC reserves, Rubin says that Canadian oil sands may become one of the world's most valuable energy sources as well as one of the few still open to private investment.

Background

Bodycote Coventry, located literally within 5 minutes from the M6 motorway, is well placed to offer support to the manufacturing sector. The facility has a local history in excess of thirty years, which has included relocation to larger, modern premises. The plant has continued to grow and, with continual investment in equipment and personnel, now offers probably the largest vacuum capacity within the UK.

This includes several front loading vacuum furnaces and two large vertical bottom loading furnaces. To further enhance the plant list, there is an additional range of air furnaces with operating temperatures up to 1080ºC. Ancillary services include a cryogenic facility, TIG welding, a hot vapour degreasing facility and an on-site laboratory.

The Bodycote Heat Treatment, Coventry facility has earned a reputation as a provider of premium metallurgical services. A close inspection of the plant will demonstrate high investment in leading edge technologies with designated preparation areas manned by our skilled and experienced workforce.

The diversity of our customer base, with the need to continually develop engineering solutions, has gained recognition for the Bodycote Coventry facility and established the plant as a market leader.
Markets Served

Bodycote Heat Treatment serve sectors inclusing:

· Aerospace

· Power Generation

· Automotive

· Off-shore & Petrochemical

· Medical, Scientific & General Engineering
Heat Treatment Services Offered at Bodycote Heat Treatment, Coventry

Bodycote Heat Treatment’s Coventry facility offers services including:

· Vacuum heat treatment

· Vacuum Homogenisation

· Normalising

· Vacuum hardening

· Vacuum precipitation

· Air heat treatment

· Assembly and vacuum brazing
Vacuum Heat Treatment

A clean, cost effective and reliable method of processing metals.
Vacuum Homogenisation

Vacuum homogenisation and solution heat treatment of investment castings.
Normalising

A widely used process to refine the grain structure prior to hardening.
Vacuum Hardening

Hardening of materials in a non-oxidising atmosphere minimising distortion.
Vacuum Precipitation

Ageing in a non-oxidising atmosphere.
Air Heat Treatment

A cost effective thermal processing method, mainly used on materials requiring further machining after treatment.
Assembly and Vacuum Brazing

Universally accepted as a versatile, high integrity method of joining metals. A precision metal joining technique, ideal for many component configurations and suitable for a wide range of materials. Examples include gas turbine components in highly stressed conditions.
Facilities Available at Bodycote Heat Treatment, Coventry

Key facilities and capacities available at Bodycote Heat Treatment, Coventry are outlined in the following sections.
Vacuum Furnaces

Range of seven vacuum furnaces from 77mm × 1220mm × 584mm to 900mm × 1220mm × 600mm with a maximum temperature of 1400ºC.
Air Furnaces

Complemented by four air furnaces from 760mm × 890mm × 760mm to 1300mm × 2270mm ×1265mm with a maximum temperature of 1100ºC.
Cryogenic Facilities

Cryogenic facility (925mm × 1790mm × 660mm) with temperature from 0ºC to -100ºC.
Degreasing Facility

Degreasing facility (trichloroethylene).
Hardness Testing

Two hardness testing machines capable of testing a large range of materials.
Welding

Resistance and capacitor discharge welding.

AZoM - Metals, ceramics, polymers and composites - furnaces available at Bodycote Heat Treatment's Coventry plant. Parts produced at Bodycote's Coventry plant.
Accreditations
Quality Accreditations

The facility boasts many major international accreditations including ISO 9001:2000, AS/EN 9100, TS 157, Nadcap, accreditation, demonstrating world-class standards.
Environmental Accreditation

Bodycote Coventry also holds ISO 14001 accreditation.

Background

Bodycote Cambridge offers unrivalled service in Vacuum Heat Treatment, Vacuum Brazing and Electron Beam Welding. The facility, with a history in excess of thirty years, continues to support local engineering and the manufacturing sector from it’s location in Waterbeach.

The facility offers a comprehensive range of equipment to meet the needs of an extensive and diverse customer base. A policy of continuous improvement and customer focus has resulted in a development of a range of equipment including Vacuum and Air furnaces, complementing their metal joining capabilities with Electron Beam Welders, offering multi-chamber size capability.

To complement these three core activities, Bodycote Heat Treatment, Cambridge offers ancillary processes including:

· TIG welding

· Cryogenic treatment

· Hot vapour degrease

· Aqueous wash capability.

The diversity of our customer base, with the need to continually develop engineering solutions, has gained recognition for the Bodycote, Cambridge facility as a provider of quality vacuum heat treatment and metal joining services.
Heat Treatment Services Offered by Bodycote Heat Treatment, Cambridge

Processes at Bodycote, Cambridge include:

· Vacuum homogenisation

· Stress relieving

· Normalising

· Vacuum hardening

· Vacuum precipitation

· Assembly and vacuum brazing

· Electron beam welding
Vacuum Homogenisation

Vacuum homogenisation and solution heat treatment of investment castings.
Stress Relieving

Used as a controlled process to reduce residual stresses in part machined materials.
Normalising

A widely used process to refine the grain structure prior to hardening.
Vacuum Hardening

Hardening of materials in a non-oxidising atmosphere minimising distortion.
Vacuum Precipitation

Ageing in a non-oxidising atmosphere.
Assembly and Vacuum Brazing

A precision metal joining technique, ideal for many component configurations and suitable for a wide range of materials.
Electron Beam Welding

This reliable, efficient and cost effective metal joining technique, with its extensive list of benefits, has become a formidable tool in today’s competitive engineering market.
Markets Served

· Aerospace & Automotive

· Power Generation

· Off-shore & Petrochemical

· Medical, Scientific & General Engineering
Facilities Available at Bodycote Heat Treatment, Cambridge

The following pieces of equipment are available at Bodycote’s Cambridge plant:

· Four electron beam welders from 225mm × 225mm × 225mm to 455mm × 455mm × 455mm, rated at 6 kW.

· A range of four vacuum furnaces from 457mm dia × 500mm deep to 1270mm dia × 1370mm deep with a pay load up to 1000kg and a maximum temperature of 1200ºC.

· Complemented by two air furnaces from 610mm dia × 610mm deep to 1000mm dia × 1000mm deep with a pay load up to 750 kg and a maximum temperature of 750ºC.

· Two degreasers

· One cryogenic unit: 610mm × 610mm ×


1200mm with a pay load up to 250kg and a temperature from 0ºC to -100ºC.

· One TIG Welder

· One Resistance Welder

AZoM - metals, ceramics, polymers and composites - facilities offered at Bodycote Heat Treatments, Cambridge plant
Accreditations
Quality Accreditations

The facility holds many major accreditations including ISO 9001:2000, Nadcap, AS/EN 9100, TS 157, demonstrating world-class standards. Our highly experienced management team are able to offer support and advice to meet your metallurgical needs.

Background

Bodycote provides world class services and have an international reputation for total reliability and unrivalled expertise in all significant heat treatment processes. Vital capacity and unmatched investment in all industrially important treatments and leading-edge fully computerised heat treatment centres are complemented by sophisticated metal joining facilities.

Bodycote Heat Treatments is a vital link in the manufacturing process for the aerospace, power generation, automotive, railway and general engineering industries. Total quality commitment, international quality accreditations and numerous customer approvals, means that 24 hours a day, 7 days a week, Bodycote guarantees world-class standards.

Bodycote Heat Treatments, combined with the Group's other services, can offer manufacturers comprehensive services with guaranteed capacity from strategically located international facilities.
Reasons to Choose Bodycote Heat Treatment

There are several reasons why you should choose Bodycote Heat Treatment for all your heat treatment requirements. These include:

· Furnaces, Controls and Management Systems are validated by the main engineering OEM's.

· Bodycote Heat Treatment Centres hold all of the industrially important quality accreditations.

· Process and production controls are linked with transport services, to deliver optimum logistics solutions for supply chain customers.

· Bodycote's trained and experienced personnel are eager to ensure that all customers’ components are treated with care throughout.

· We never forget that the customer has invested time, money and resources in all the components we heat treat.
Global Facilities

For the convenience of their clients, Bodycote Heat Treatment has facilities in:

· Austria

· Belgium

· Canada

· Czech Republic

· Denmark

· Finland

· France

· German


· Hungary

· Italy

· Liechtenstein

· Netherlands

· Sweden

· Switzerland

· UK

· USA
Metals Heat Treated

Bodycote Heat Treatment have facilities to be able to heat treat the complete range of metals including:

· Aluminium alloys

· Cast irons

· Cold work tool steels

· Engineered steels

· High speed steels

· Hot work tool steels

· Low alloy steels

· Magnetic alloys


· Nickel alloys

· Nimonic alloys

· Non-ferrous alloys

· Plastic mould steels PN parts

· Sintered metals

· Stainless steels

· Titanium alloys

· Tool steels
Heat Treatment Services Offered by Bodycote Heat Treatment

Bodycote Heat Treatment offer a full range of thermal processing services such as:

· Ageing and Precipitation Hardening

· Annealing

· Austempering

· Boronizing

· Brazing

· Carbonitriding

· Carburizing

· Cryogenic treatment

· Electron Beam Welding

· Ferritic and Austenitic Nitro Carburizing

· Gas Nitriding

· Hardening & Tempering

· Homogenising

· Induction Hardening


· Kolsterising

· Low Pressure Carburising

· Malcomizing

· Marquenching

· Nitriding

· Normalizing

· Plasma Nitriding

· Shot Peening and Shot Blasting

· Straightening

· Stress Relieving

· Vacuum Brazing

· Vacuum Degassing

· Vacuum Heat Treatment

Some of these processes are outlined in the following sections.
Ageing and Precipitation Hardening

Also known as Age-Hardening or Precipitation Hardening.

Some alloys including aluminium alloys, beryllium copper and special stainless steels are capable of being hardened by solution treatment followed by ageing. The hardening results from the time dependant precipitation of a hard compound from the solid solution, during the ageing cycle. The process is carried out in the temperature range 100 to 200°C for aluminium and copper alloys and 400 to 700°C for those steels which are suitable. Generally optimum strength is developed by the use of lower temperature and longer treatment time. In order to carry out manufacturing operations on these alloys it is often necessary to soften them by re-solution treatment or over-ageing at a temperature which is intermediate between the solution and ageing temperatures. The required mechanical properties can then be produced by ageing. In most applications this can be achieved without the need to re-solution treat.
Annealing

Annealing is the term given to a class of heat treatments used to soften metals, to allow metalworking operations to be carried out economically and without damage to the work-piece or tooling. Annealing improves hot and cold working characteristics, increases machinability, reduces internal stresses arising from machining, forging, pressing and welding, and also conditions material for subsequent hardening operations. Full annealing consists of heating the work-piece to above the upper critical temperature and slow cooling, usually in the furnace. It is generally only needed for the higher alloy steels, cast irons and complex alloys. Long treatment times are necessary to produce optimum softening in the case of the higher alloy steels. Where it is considered desirable to fully austenitise a steel during a softening process, (e.g. in order to refine forged structures), but where economy is paramount, a normalising treatment is often applied instead of a full anneal. This consists of the same initial heating stage as full annealing but followed by removal of the work from the furnace for air-cooling. Normalising is only applicable to the lower alloy and plain carbon steels.

Sub-critical annealing is, as the name implies, carried out at temperatures below the lower critical temperature. It is mainly carried out in the temperature range 630 to 700°C. It reduces hardness by allowing recrystallisation of the microstructure to occur. Alternatively, if a temperature just below the lower critical temperature is used (690 to 710°C), it is possible to produce spheroidisation of the cementite phase instead of forming the normal lammellar pearlite and ferrite structure. Spheroidising is a useful technique for softening high carbon steels to improve machinability. Lower temperature sub-critical anneals in the temperature range 550 to 680°C. are used to stress relieve welded fabrications and to stabilise rough machined components which are to be ultimately hardened and tempered, case hardened or nitrided and whose dimensional stability is critical
Austempering

Austempering uses molten salt or a fluidised bed as a quenching medium. Austempering consists of a two step process, austenitizing and isothermal transformation in an austempering bath whereas convention heat treatment consists of three steps; austenitizing, quenching, and tempering.

Molten salts used in Austempering transfer heat rapidly. The salts are completely soluble in water which facilitates subsequent cleaning operations. Austempering increases ductility and reduces product distortion.

Austempering is a great alternative to conventional heat treating, especially for springs and stampings that require precise dimensional control. The reduced distortion from the austempering process can lessen subsequent machining time, stock removal and cost. The clean "blueish" non-oily surface allows for ease of product handling and is very receptive to subsequent operations such as painting, plating, etc.
Boronizing

Boronizing is a thermochemical surface treatment in which boron atoms are diffused into the surface of a workpiece to form borides with the base material. When applied to the appropriate materials, boronizing provides wear and abrasion resistance comparable to sintered carbides.
Brazing

Bodycote’s extensive brazing and joining experience provides all the benefits of clean, pressure tight joints, with the added ability to handle mass production volumes.

Fabricating components from pressed and turned steel parts will frequently show a considerable saving in costs due to reduced material content, reduced machine time and less expensive capital plant.

Because of the special properties of the process, secure, leakproof joints can be achieved on assemblies which are complex, irregularly shaped and intricate (as well as the more straight forward), at costs which are often markedly lower than those which can be achieved by other conventional methods.
Carbonitriding

A thermochemical treatment involving the incorporation of both carbon and nitrogen into the surface of the component simultaneously. This process is carried out at a lower temperature than carburising and therefore components are less prone to distortion. The use of nitrogen as well as carbon allows carbonitriding to be used on lower alloy steels and plain carbon steels.
Electron Beam Welding

A reliable, efficient and cost effective metal joining technique.

Bodycote has the largest Electron Beam Welding facility in Europe at their disposal, project management teams are on hand to discuss your individual requirements, assist in solving your specific problems and to suggest methods of improving your individual engineering projects. Advantages

· Vacuum process, yields clean reproducible, high integrity joints

· Low heat input with minimal distortion and a narrow heat-affected zone

· Weld penetration of up to 30mm+ Metals of dissimilar melting points and thermal conductivities can be welded

· Quantities from one-off development to large production batches can be accommodated.

· 14 machines, range from 9” cube to 9’x5’x6’
Ferritic and Austenitic Nitro Carburizing

Bodycote Thermal Processing provide a comprehensive range of nitrocarburizing treatments, encompassing the ferritic and austenitic processes. Whilst Ferritic Nitrocarburizing is the more generally specified process, the greater load bearing capability of the austenitic treatment has resulted in its adoption as an attractive alternative to the high temperature surface hardening techniques.

Austenitic nitrocarburizing produces a transformation zone of martensite and austenite in addition to the compound layer. Components manufactured from plain carbon steels and processed by Austenitic Nitrocarburizing can have a surface hardness of up to 750 Hv5, whilst retaining most of the property improvements of the ferritic process.
Hardening and Tempering

The optimum combination of hardness, strength and toughness is developed throughout the cross section of an engineering product made from steel, by means of hardening and tempering. This treatment consists of heating the work-piece to an appropriate hardening temperature, which is dependant upon the particular steel analysis involved, holding for sufficient time to ensure the whole work-piece is at temperature and then rapidly cooling it in a suitable medium (quenching). This medium can be air, oil, water, molten salt, a fluidised bed or a pressurised inert gas, such as nitrogen. Selection of the quench medium is dependant upon steel analysis, component geometry, the heat treatment furnace used and the manufacturing stage at which hardening and tempering is carried out. The resultant temperature changes induce physical transformation of the steel, resulting in mechanical property changes.
Induction Hardening

Exposing a steel work-piece to an electro-magnetic field produces a heating effect in the surface of the work-piece, by the phenomenon known as induction. This surface heating produced by the induced electro-magnetic current in the work-piece, can be used for softening, hardening or metal joining operations, depending upon the steel, the work-piece environment and particular temperature changes employed. The most common application of induction treatment is in the hardening of steel components with carbon contents of between 0.4 and 0.5%. A copper induction coil is made to surround the work-piece and the surface temperature is raised to above the upper critical temperature in a few seconds. For most applications high current frequencies of 200kHz or above are used or alternatively medium frequencies of up to 10kHz. A quenching spray of a suitable solution follows the inductor as it traverses the work-piece, providing rapid cooling to produce the full hardening transformation of the heated zone.
Kolsterising

Kolsterising is surface hardening process primarily for austenitic stainless steels. Wear resistance and resistance to galling is improved, while corrosion resistance remains unchanged.

The process involves diffusion of carbon into the work piece surface without the formation of chromium carbides. Post treatment surface hardness is equivalent to between 70 and 74 HRc. Standard case depths offered are 22 or 33 microns.
Malcomizing

Malcomizing is a nitriding process for stainless steels. High hardness and excellent corrosion resistance properties can be achieved with this low temperature process.
Marquenching

Marquenching® or martempering of steel consists of quenching the steel in hot oil at 150-175°C, and holding it in the quenching medium until the temperature of the workpiece is essentially uniform and equal to the temperature of the oil. This minimizes or eliminates distortion of the workpiece which occurs from unequal transformation rates normally found in conventional quenching.
Nitriding

Specified wherever freedom from distortion is of paramount importance to a wear resistant or fatigue prone component, nitriding has become an established process within many fields of engineering. Recognising the need for improved process control to offset the disadvantage of lengthy processing times, Bodycote pioneered the use of infra-red analysis and computerisation to monitor and control the ammonia dissociation. This, coupled with a wide range of regularly operated cycles, enables Bodycote to provide a systematic turn-round of customers’ work, irrespective of the case depth required.
Shot Peening and Shot Blasting

A specialist fatigue improvement service, utilising automated shot peening for heat treated transmission components.
Straightening

A specialist computer controlled, fully automated shaft straightening service for previously case hardened transmission components.
Stress Relieving

Facilities are provided for the stress relieving of castings and fabrications, ranging in size from small items up to large complex assemblies weighing 80 tonnes.
Vacuum Heat Treatment

Bodycote’s range of furnace types and sizes, coupled with our treatment and inspection expertise, makes the vacuum facilities of interest to a wide range of engineering customers in the Aerospace, Toolmaking, Nuclear and Oil Industries, wherever a high standard of reliability of heat treated product is paramount.

Background

Aluminium plate and extrusions are used extensively in the superstructures of ships where the designers wish to increase the above waterline size of the vessel without creating stability problems. In hovercraft and in the various types of surface skimming vessels, such as fast mulithulled catamarans, (figure 1), the weight advantage of aluminium has enabled marine architects to obtain more from the available power.

Figure 1. The use of large aluminium extrusions gives quality and cost benefits in fast multihulled catamarans.

On offshore oil platforms, aluminium has become the established material for helidecks and helideck support structures because of weight and through life maintenance advantages. For the same reasons it has found frequent use in stair towers and telescopic personnel bridges. Aluminium accommodation modules have been installed on the Snorre and on the Statfjord C platforms in the Norwegian sector of the North Sea. These modules have provided a range of benefits. An overall weight saving of the order of 40% compared to steel has been achieved in the case of the Snorre accommodation module. Cost advantages were obtained in the case of Statfjord C as a result of using only 60 tonne maximum load capacity platform crane for erection and assembly purposes.

Market Influences

In world ship building, certain types of vessels are increasing in popularity. The interest in cruise holidays has surged and whereas it was once simply a matter of converting former ocean liners, purpose built vessels are one of the fastest growing sectors of the industry. New fast ferries which can dramatically shorten journey times are entering service around the world.

The oil industry is seriously affected by the fall in world oil prices. If more marginal fields, for example some of the more difficult North Sea finds, are to be exploited then the costs of oil production hardware will have to be lowered. These market conditioned are pressurising designers, for a variety of technical reasons, to lower effective weight of structures, to cut construction costs and to reduce through life maintenance requirements.

If composite construction is adopted and very high strength fibres are used, fibre reinforced plastics can sometimes be an option to reduce weight, but problems can occur because of high material costs, high moulding costs and difficulties with fire ratings. Often the only feasible way of lowering weight is to adopt or change to aluminium.

Construction costs are very dependant on joining/assembly techniques. If joining can be reduced or made more simple by, for example, using the largest available extrusions or/and, where acceptable, using mechanical joints as opposed to welds, then construction times and hence costs can be lowered. The proven corrosion resistance of unprotected aluminium alloys in marine conditions, for example, the plate alloy AA5083 or the extrusion alloy AA6082, is well documented. This advantage over constructional steel has a considerable influence on through life maintenance costs.

Following the 1988 North Sea Piper Alpha oil and gas platform disaster, which claimed 167 lives, the new approach to safety has meant that accommodation modules are now installed on offshore structures as far away as possible from the more dangerous operations. This frequently means that the weight of the living quarters module is a factor which has a major influence on new build project costs.

Since the first offshore platforms were built, considerable advances have been made in the techniques for recovering ever higher proportions of hydrocarbons from the layered geological structures below the sea bed. These improved techniques have often meant that additional heavy pieces of equipment have had to be installed on the existing offshore facilities. Many of these ageing platforms are approaching their maximum designed topside weight. It is usually much cheaper to replace parts of an existing installation with new light weight modules than to install a completely new structure.

Properties Of Large Extrusions

The mechanical properties of extrusions are influenced by grain size. This in turn is largely determined by recrystalisation characteristics of the alloy, extrusion ratio, extrusion temperature and final heat treatment. The flow of material in the extrusion process causes a directionality of mechanical properties. Transverse proof stress and UTS are 85-90% of the longitudinal values.

One of the main advantages of the aluminium extrusion process is its ability to provide complex hollow shapes. Most hollow profiles are produced from die tooling which forms welds during the extrusion process. Judged by the criteria appropriate for the more familiar fusion welds, there would seem to be no problems with extrusion welds. Composition is constant, there is no filler metal and there is no liquid to solid phase change. Nevertheless, properties across the weld can differ from those of the parent metal because of differences in grain size and variations in the distribution of intermetallic phase particles.

The term extrusion weld covers two types of weld: seam welds formed when two streams of metal flow together in the die, and charge welds formed at the die ports between successive billets. Both types are solid state welds formed under deformation and pressure. From a correctly designed die it is very difficult to form a low quality seam weld. Quality problems from charge welds are unfortunately far more frequent if correct operating procedures at the press are not followed.

It is most important that the correct length of extruded material is scrapped at the start and end of each billet in order to ensure that the low property material is removed. Proportionally large billets are required for large extrusions to provide a sufficient length of material to allow the potentially defective front and back ends to be removed. This means, particularly for extrusions with high cross-sectional areas, that high extrusion pressures and not just large diameter press containers are essential.

Table 1 shows minimum property values for extruded AA6082 T6 material in the longitudinal and transverse directions and includes minimum transverse values taken across extrusion welds. The table also shows values of mechanical properties of AA6082 butt welds for comparison purposes.

Table 1. Mechanical properties of aluminium extrusions (minimum values)

Extruded AA6082 T6
Thickness range (mm)		-5	5-10	10-30
Longitudinal	0.2% Proof stress (MPa) UTS (MPa) Elongation A5(%)	260 310 10	260 310 10	260 310 10
Transverse no extrusion weld	0.2% Proof stress (MPa) UTS (MPa) Elongation A5(%)	245 290 8	245 290 8	235 280 6
Transverse with extrusion weld	0.2% Proof stress (MPa) UTS (MPa) Elongation A5(%)	245 290 5	245 290 8	230 260 3
Butt weld AA6182, filler rod AA5356/5183
Thickness range (mm)			-15	15-25
0.2% Proof stress (MPa) UTS (MPa) Elongation A5(%)			115 185 3-5	95 165 3-5

The longitudinal fatigue strength of AA6082 T6 after 107 cycles at stress ratio(R) = 0, is quoted typically as 130MPa. Fatigue tests made transverse to the extrusion direction give results of approximately 80% of this longitudinal value. Extensive testing of fusion welded flooring sections containing extrusion welds has shown that failures usually occur at the fusion welds or in the heat affected zone on either side of the weld seam.

Fatigue characteristics of samples taken transverse to the extrusion direction containing extrusion welds are similar to transverse values from the base material, always with the proviso that sufficient front end extrusion scrap has been removed to provide satisfactory extrusion weld quality. Large extrusions have better fatigue characteristics than similarly dimensioned assemblies of small extrusions fusion welded together.

Joining Methods

MIG and TIG welding have been in use for many years and have established themselves as reliable techniques when the correct procedures are employed. The various problems which can arise have also been studied in detail. Typical defects are shown in figure 2. The four fusion weld defects represented in the diagram affect different aspects of the mechanical properties of the base material. Whereas the local heating, over ageing and consequent softening of the heat affected zone on either side of the weld bead lowers proof stress and UTS, the micro and macro porosity and shrinkage defects can act as sites for fatigue initiation and as a result can lower fatigue properties.

Figure 2. Possible quality problems in fusion welds

In addition to problems caused by weld flaws, fatigue strength is affected by mechanical factors such as holes, threads and grooves and also by the positioning of flaw free welds. However, extrusion technology can be used to position fusion welds in non critical areas or to enlarge the section close to a weld in order to compensate for the loss in properties caused by the welding process.

The design rules for fatigue of aluminium structures are covered by a number of standards including British code BS8118 Structural use of aluminium and the European code ECCS - paper, Doc 68 European recommendations for aluminium alloy structures fatigue design. Of the two codes the British Standard is in general the more conservative. An efficient quality assurance system is needed to monitor and guarantee both performance of welding equipment and workmanship.

Often the most convenient and technically optimum way of joining two or more aluminium extrusions is to use a specially designed mechanical fixing arrangement. The combination of relatively few welds with a high proportion of mechanical joints has become standard for helidecks. In the latest designs for offshore accommodation modules, the outer skin is a welded structure and selected parts of the interior have been designed to incorporate mechanical joints with sealants between the individual flooring sections.

Fast Catamaran Deck Design

By making use of large extrusion technology simply to reduce the amount of welding, considerable quality and cost benefits can be obtained. Benefits from use of large extrusions in more complex parts of a structure than the deck are more difficult to quantify but nevertheless real. The advantage of being able to free more parts of the design from the potential difficulties created by the need to thoroughly inspect the fusion weld joining two standard extrusions can easily be appreciated.

Offshore Module Design

The Snorre accommodation module was built using more than 20 different profiles, some of which were relatively difficult hollow sections. The welded design needed some 780 tonnes of aluminium making it the largest all aluminium structure ever built. The total finished weight of the Snorre accommodation module was 2100 tonnes. The Statfjord `C' accommodation module was based on the same basic components as were used for Snorre.

It was considered that a design change should make possible a lower weight, lower cost module. The design change has involved reducing and simplifying the number and type of extruded sections and moving to a combination of welded and mechanical joints to lower construction costs. Since the new design requires relatively few profiles it is intended that these be held in stock to make virtual off the shelf delivery a possibility. This will make modules available in the very short delivery times, important for the offshore refurbishment market. The primary and secondary beams and ternary decking have been so designed to allow flexibility inside the module so that heavy items can be supported in the structure with relatively little design input.

Background

Materials selections must be given detailed attention at every stage of the design, construction and operation of systems and equipment for application in offshore oil and gas production. Full attention must be given to general corrosion resistance, selective corrosion resistance (by pitting and crevice attack) and stress corrosion cracking susceptibility in sour hydrogen sulphide environments if failures, loss of production and costly maintenance are to be avoided. Even more important than these considerations is the need to maintain offshore safety. Thus the specification and use of materials which combine corrosion resistance with high mechanical strength is a fundamental requirement.

A greater understanding of the offshore environment and more detailed knowledge of the conditions under which offshore structures and systems have to operate will obviously contribute to the selection of the correct materials.
Corrosion in Sea Water and Offshore Environments

Sea water is highly corrosive and offshore installations are often exposed to temperature extremes. The corrosion resistance of a material is therefore equally as important as mechanical strength. The introduction of chlorine by adding hypochlorite solution to sea water to give biofouling resistance can reduce the corrosion resistance of certain stainless steels, particularly under crevice conditions. Hydrocarbon process systems often have to withstand the potentially corrosive effects of hydrogen sulphide and acid conditions associated with the dissolved carbon dioxide which is often present. Corrosion can weaken elements of an otherwise well designed ,structure or affect individual equipment components to such an extent that they cease to be serviceable. Unfortunately, the fight against corrosion itself can lead to equally damaging side effects such as the release of nascent hydrogen. This can be generated as a result of cathodic protection measures adopted to protect a structure or by dissimilar metal coupling. The presence of such hydrogen can given rise to hydrogen-induced cracking of steels and nickel base alloys.
Alloys for Offshore Applications

Metals manufacturers have spent much time and effort in developing alloys specifically to meet offshore needs. The alloys developed have had to be suitable for shafts and bolting as wellas many other applications. These have included sea water and process pipework, water injection and booster pumps, line shaft pumps, emergency shutdown valves, anchorages and tensioners for riser protection systems, multiphase pumps and remotely operated vehicle components.
The Development of Marinel

One particularly significant corrosion-resistant alloy (CRA) development led to the introduction of an ultra high strength cupronickel alloy (Marinel), approximately five years ago. This alloy was added to the range of alloys available for selection with reference to particular equipment where corrosion and hydrogen embrittlement could occur offshore. Most high strength iron and nickel based alloys and titanium alloys are prone to hydrogen embrittlement, the effect usually becoming more severe as the strength increases. Thus these alloys when operating in a high-stress condition will be more susceptible to hydrogen embrittlement than the same alloys operating under lower stress. Hydrogen embrittlement is of particular concern where high strength (usually B7 carbon steel, 720 N.mm-2 yield point) bolting is used on subsea structures. The operating stress level usually taken to represent a critical situation with respect to hydrogen embrittlement is that given by the yield stress of B7 carbon steel which has the value of 720 N.mm-2.
Use of Cathodic Protection

Cathodic protection by sacrificial anodes or impressed current is extensively used to protect subsea structures from corrosion. This technique can generate hydrogen which, if absorbed, may lead to embrittlement of metallic components with the resultant danger of premature failure. The time-dependent nature of the ingress of hydrogen may mean that an apparently unaffected subsea critical component, for example a bolt, fails in an instant after it has performed satisfactorily for several years in service. Failure occurs when the residual ductile core is reduced in area by an encroaching hydrogen embrittlement front to a cross-section which cannot carry the load placed upon it. As an example, the failure of alloy K-500 riser clamp bolts has been reported in the April 1985 issue of Materials Performance (p37). Charging of UNS N 05500 (high strength 70Ni-3OCu alloy) with hydrogen has been shown to result in the hydrogen embrittlement of nonmagnetic drill collars. This has been thought to be due to galvanic coupling of the collars with carbon steel (see the October 1986 issue of Materials Performance, p28). It has also been suggested that a documented example of cracking in high strength steel legs of jack-up rigs was associated with hydrogen-induced stress corrosion cracking, the hydrogen being generated by the cathodic protection system operating in hydrogen sulphide contaminated seawater (February 1989 issue of Veritec Offshore Technology Journal).
Transport of Hydrogen into a Metal

The entry of hydrogen into a metal can be purely diffusion-controlled, or can be assisted by dislocation transport and the latter effect has been experimentally demonstrated by the measurement of hydrogen permeation rates through nickel whilst it is undergoing plastic deformation (see volume 13, 1979 of Scripta Metallurgica, pp 927-932). Dislocation sweep-in of hydrogen from the surface in the case of several different metals has been found to be consistent with the calculated energy of activation of hydrogen-induced cracking (see pp 233-239 of the proceedings of the 1976 TMSAIME international conference on the effects of hydrogen on the behaviour of metals). During hydrogen transport, the hydrogen can be deposited at various ‘trap-sites’ or internal discontinuities such as grain boundaries or precipitates.
Susceptibility to Hydrogen Embrittlement

These can take the form of ‘reversible’ traps which the hydrogen can subsequently leave, or ‘irreversible’ traps, which the hydrogen cannot leave and which tend to encourage local fracture through a lowering of the surface energy of the material. The effectiveness of the traps in promoting hydrogen embrittlement is related to the degree of strengthening present in the material matrix, as it is well established that materials in a higher strength state (i.e. cold worked or age hardened) are more susceptible to hydrogen embrittlement than the same materials in a lower strength condition. Thus, measurement of both the hydrogen entry kinetics of a metal (or alloy) and the ability of the metal to trap hydrogen would give an indication of its hydrogen embrittlement susceptibility. Overall solubility of hydrogen does have an influence on hydrogen embrittlement characteristics, as iron, nickel and titanium have relatively high hydrogen solubilities (>1cc/cc) and these materials are more susceptible to hydrogen embrittlement than aluminium and copper alloys, whose solubilities are generally less than 0.1 cc/cc. The hydrogen diffusion coefficients of steel and titanium are greater than 10-6 cm2.s-1, whereas the hydrogen diffusion coefficients of nickel, aluminium and copper alloys are approximately 10-10 cm2.s-1, although this does not take into account dislocation transport or grain boundary diffusion.
Nickel-Copper Alloys and Hydrogen Embrittlement

Two alloys which are interesting to compare are the age hardening nickel-copper alloy K-500 and age hardening cupronickel Marinel, which have similar mechanical properties and hydrogen diffusion characteristics. In comparing the chemical composition of these two alloys, see Table 1, it is apparent that they contain almost the same basic elements, the major difference between them being the Cu:Ni ratio. In the case of Marinel the high Cu:Ni ratio renders the alloy immune to hydrogen embrittlement and this has been found to be largely due to the reduced ability of this alloy to trap the hydrogen irreversibly.

Table 1. Typical composition of bolting.

Material


Ti


Cr


Mn


Nb


Cu


Ni


Fe


Al

K-500


0.6


-


1.0


-


30


Bal.


1.0


2.8

Marinel


-


0.4


5.0


0.7


Bal.


18


1.0


1.8
Marinel in Offshore Applications

In offshore situations many developments have widely employed Marinel bolting for splash zone and subsea. Bolting subsea has been used with 13Cr steel, 22Cr duplex and 25Cr duplex steel manifold, valve and choke flanges. Subsea developments using the alloy include Lyell, Strathspey, Nelson, Heidrun, Johnston and Nelson.

Good galling resistance obviates the need for a lubricant during assembly and nuts can be readily removed after a period of service if required.

For the Conoco Lyell subsea manifold Marinel bolting was chosen for its greater mechanical strength and corrosion resistance compared with grade 660 steel. The bolts were bolt tensioned and assembled without lubricant. Stud bolts have been subjected to a laboratory examination after 18 months service (nearly 12 months with the manifold in operation) and apart from the expected calcareous deposit, appeared completely unaffected by service.
Duplex Stainless Steels in Offshore Applications

A most significant contribution to the fight against corrosion offshore has been made by duplex stainless steels. These have often been adopted on offshore structures in preference to carbon steel or other stainless steels. The value of the duplex stainless steel is that it combines the basic toughness of the more common austenitic stainless steels with the higher strength and improved corrosion resistance of ferritic steels. The optimum chemical composition of these steels provides a high level of corrosion resistance in chloride media together with high mechanical strength and ductility. Other benefits include the ability of some duplex stainless steels to be used at quite low sub-zero temperatures and be able to resist stress corrosion cracking.

A significant feature of duplex stainless steel is that its pitting and crevice corrosion resistance is greatly superior to that of standard austenitic alloys. Pitting resistance equivalent numbers (PREN), a standard industry measure, are often in the high 30s while the latest duplex alloys exceed a PREN of 40. This is an increasingly common specification for certain offshore duties. However, PREN numbers only provide an approximate grading of alloys and do not account for the microstructure of the material. An acceptance corrosion test on material in the supply condition is so much more meaningful.
The Evolution of Duplex Stainless Steels

Ferralium alloy 255 was the world’s first commercial 25% chromium duplex stainless steel when it was introduced over 20 years ago. It pioneered the use of a deliberate nitrogen addition in order to improve ductility and corrosion resistance. Further research has demonstrated the importance of using duplex stainless steels containing both nitrogen and copper.
Super Duplex Stainless Steels for Offshore Applications

For offshore and indeed, onshore applications, the availability of a super duplex (25% chromium) stainless steel alloy in a variety of forms is important. For example, bar, forgings, castings, sheet, plate, pipe/tube, welding consumables, flanges, fittings, dished ends and fasteners are available. In terms of other benefits, the high allowable design stress of this alloy type in comparison with other duplex stainless steels and austenitic stainless steels, including 6% Mo type, is significant. It also offers excellent castability, weldability and machinability. These features are complemented by excellent fatigue resistance and galvanic compatibility with other high alloy stainless steels.

Twenty-two percent chromium stainless steels provide better pitting resistance and resistance to crevice corrosion than type 316 stainless steel by virtue of a more stable passive film and also have greater mechanical strength. However, for optimum corrosion resistance, a 25% chromium high alloy duplex stainless steel is required and these alloys are often referred to as super duplex stainless. Even within this category, it is important to select the correct grade of material to get versatility in handling a wide range of corrosive media and for confidence that the alloy will cope with any excursions or transient operating conditions which make the environment more aggressive.
Materials Selection for Offshore Applications

Offshore structures themselves present different requirements of materials depending upon whether their application is topside, splash zone or subsea. Topside, duplex materials are suitable for a wide range of bolting applications and material such as Ferralium alloy 255 provide up to B7 steel strength, excellent corrosion resistance and a service life equal to the life of the system, thereby contributing to reduced maintenance costs. In the splash zone, the alloy has already demonstrated its suitability for sea water resistance with over 15 years service on North Sea installations and has been widely employed for riser bolting and components on riser protection system on TLPs.
Emergence of New Super Duplex Stainless Steels

Improved materials in the super duplex stainless steel category continue to be developed by manufacturers offering better or differently combined characteristics, features and benefits. These alloys, generally with a PREN > 40, are produced to conform to a number of UNS designations which appear in ASTM product form specifications. Castings and wrought forms are available. Typical of recent developments is Ferralium alloy SD40 (conforming to UNS S 32550) with a PREN > 40.0 and providing a minimum 0.2% proof stress of 550N.mm-2 and a UTS of 760 N.mm-2. This 25% chromium super duplex material results from a carefully controlled composition and balanced austenitic/ferritic structure with a substantial content of molybdenum and nitrogen.
Applications for Super Duplex Stainless Steels

Applications which can benefit from the use of these high alloy super duplex steels involve piping systems, pumps (where the good erosion and abrasion resistance is employed), valves, heat exchangers and diverse other equipment.

Recently, the excellent corrosion resistance of the new super duplex Ferralium alloy SD40 has been exploited for subsea electrical connectors on the Saga Snorre and Total South Ellon developments. In one case the super duplex material was chosen to replace standard austenitic stainless steel which had suffered from corrosion attack.

Figure 1. Super duplex stainless steel alloy is available in a variety of forms for both on and offshore applications.
Conclusions

Several types of alloys have been developed in recent years to combat the degradation of existing alloys by corrosion attack and in some cases hydrogen embrittlement in the harsh offshore environment. Super (25 Cr) duplex stainless steels and an ultra high strength cupronickel have provided the solution to many material selection dilemmas.

Polymer Type

Thermoplastic
Advantages

Excellent rigidity, impact toughness, abrasion resistance, creep resistance and solvent resistance. Good appearance, hydrolytic stability fatigue endurance and low coefficient of friction. Better creep resistance, thermal stability, resistance to bases and processability than homopolymer. Higher continuous use temperature than homopolymer, about 100°C ( 212°F ) in air compared to 80°C ( 175°F ).


Disadvantages

High mould shrinkage (approximately 2%). Post moulding shrinkage of about 0.1% normally complete within 48hrs. Attacked by acids and bases, very rapid attack by nitric acid. Very poor resistance to UV radiation. Homopolymers have higher tensile strength, flexural strength, fatigue resistance and hardness. Cannot be fire retarded Explosive decomposition if processed with halogens.
Typical Properties

Property


Value

Density (g/cm3)


1.41

Surface Hardness


RR117

Tensile Strength (MPa)


73

Flexural Modulus (GPa)


2.58

Notched Izod (kJ/m)


0.069

Linear Expansion (/°C x 10-5)


11

Elongation at Break (%)


65

Strain at Yield (%)


8

Max. Operating Temp. (°C)


90

Water Absorption (%)


0.22

Oxygen Index (%)


15

Flammability UL94


HB

Volume Resistivity (log ohm.cm)


15

Dielectric Strength (MV/m)


20

Dissipation Factor 1kHz


0.0015

Dielectric Constant 1kHz


3.7

HDT @ 0.45 MPa (°C)


160

HDT @ 1.80 MPa (°C)


110

Material. Drying hrs @ (°C)


3 @ 90

Melting Temp. Range (°C)


190 - 210

Mould Shrinkage (%)


1.8

Mould Temp. Range (°C)


60 - 120

Applications

Due to low coefficient of friction, commonly used as bearings, gears and conveyor belt limits. Electric kettles and water jugs. Components with snap fits. Chemical pumps. Bathroom scales. Telephone keypads, pulley wheels, and housings for domestic appliances, showerheads, and fuel expansion tanks. Toys.