Geothermal Sources

Geothermal Sources
By Debbie Pollitt, eHow Contributor
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Nearly 90 percent of Icelandic residents use geothermal energy for heat.
Geothermal energy is literally the natural heat of the Earth — earth (geo) heat (therme) — and a renewable resource that can be used to heat buildings and generate electricity. The heat is continuously produced deep within the Earth’s core, will never run out and can be redeemed as steam or hot water. U.S. geothermal projects rose by 12 percent in 2010 and, as of 2011, nine states produce geothermal power.
Billions of years ago when the Earth was forming, large amounts of energy were caught in the middle of the planet, bonding molecules of iron and nickel together to make the Earth’s core. The core is about 4,000 miles beneath the surface on top of which are two more layers — the mantle and the crust. High temperatures are continuously produced and the deeper the layer within the Earth, the hotter the heat. Geothermal energy comes from the intense heat and is caused by the slow decay of radioactive particles, a process that happens naturally in all rocks.
Hot Spots
The Earth’s crust keeps the heat of the mantle beneath the surface but when the heat becomes so intense that it breaks through the crust, it creates patches of geothermal energy known as hot spots. Hot spots can be in the form of volcanoes or geysers. Yellowstone National Park, for example, is home to many geysers, the most famous of which is Old Faithful. Cracks and openings in the crust create ventilation points ensuring that the mantle is able to keep the Earth’s surface continuously heated. This kind of geothermal energy emerges less explosively in the form of steam, creating springs and wells of heated water.
Geothermal energy is potentially everywhere but finding it is easier said than done. Volcanoes, springs and geysers are useful indicators of geothermal reservoirs and scientists may find clues by analyzing local soil and water sources but otherwise the most reliable way to locate them is to dig deep and drill. The world’s hottest geothermal area is the Pacific Ocean’s “Ring of Fire” while America, New Zealand, Iceland and Indonesia are also countries rich in geothermal sources. U.S. geothermal systems include the Geyser’s region of Northern California, Southern California’s Imperial Valley and the Yellowstone areas of Idaho, Montana and Wyoming. Hawaii, Arkansas and Texas also have significant geothermal activity.
Advantages of Geothermal Energy
It’s a very clean source of energy as nothing has to be burnt to produce the steam to turn the turbines. Using geothermal energy produces fewer greenhouse gas emissions than other energy sources. It is available around the clock, every day of the year and is capable of reducing America’s reliance on foreign oil imports. Geothermal plants can produce cheap electricity and although the initial construction and start-up costs are high, the long-term costs are low compared to conventional power plants. There are no transportation costs and the supply is reliable, predictable and stable.
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Oil Services

Oilfield services
The unsung masters of the oil industry
Oil firms you have never heard of are booming
Jul 21st 2012 | ABERDEEN |From the Economist print edition
A TECHNIQUE called “directional drilling” has transformed the energy business. Fifteen years ago the best drillers could force a well-shaft into a gentle arc. These days shafts can be drilled vertically to a depth of several kilometres—then made to turn sharply and continue horizontally for up to 12km (or 7 miles). Will Grace of Schlumberger, an oilfield services company, likens it to dropping a plumb-line from the top of the Empire State Building and then guiding it through the rear and front windscreens of every car parked in the nearby streets.
Such technology vastly increases the area one rig can cover (see diagram). For an illustration, Mr Grace points to squiggles and shadings on a computer screen in one of the 34 offices Schlumberger operates in Aberdeen, a Scottish oil city. The lines show the progress of a well completed for a Canadian oil firm a few hours earlier. It is 13,000 feet (4,000 metres) deep and has been brought to a halt 6,500 feet horizontally away from the rig, within three feet of its target.
Instruments in the “drill-string”—as formerly inflexible steel drill-shafts are now called—are meanwhile transmitting dozens of additional measurements: of the radioactivity of the surrounding rock, its resistivity to electromagnetic waves, and so on. In this case, the rock gives a low radioactivity reading, which suggests that it is sand; its resistivity is high, which suggests it is oil-bearing. This is wizardry that few firms can match. And probably none is a regular oil company.
Oilfield services (OFS) firms such as Schlumberger are the unsung workhorses of the oil industry. They do most of the heavy lifting involved in finding and extracting oil and gas. They are far less well-known than the oil firms that hire them, but immensely lucrative. Schlumberger, with headquarters in Paris and Houston, earned profits of $5 billion on revenues of $40 billion last year. Its market capitalisation has risen fourfold in the past decade, to $91 billion. That is bigger than several international oil companies, including ENI ($82 billion), Statoil ($75 billion) and Conoco-Philips ($71 billion).
Schlumberger’s success highlights a shift in the balance of power between oil companies and their flunkeys. Until the 1990s OFS companies were far smaller and earned low margins on straightforward tasks, such as drilling vertical wells. That has changed dramatically.
With the price of oil so high, firms are scrambling to pump it out of ever more remote and costly crevices. Over the past decade the oil industry’s annual spending on exploration and production has increased fourfold in nominal terms, while oil production is up by only 12%. The big services companies, which invest heavily in technology (see chart), have been growing by around 10% a year. According to McKinsey, a consultancy, OFS companies grossed around $750 billion last year.
OFS firms come in three flavours. Some make and sell expensive kit for use on drilling rigs or the seabed. These include FMC, Cameron and National Oilwell Varco, all $10-billion-plus companies. Some own and lease out drill-rigs. These companies include Transocean, Seadrill, Noble and Rowan. The third group carries out most of the tasks involved in finding and extracting oil. It is dominated by four giants: Schlumberger, Halliburton, Baker Hughes, and Weatherford International.
Most of these firms were relatively small until the 1980s, when several oil companies decided that humdrum drilling chores were no longer worth doing in-house. Oil was easy then. Drilling yielded low margins that did not justify its claim on capital, so the oil majors outsourced it. This gave OFS firms space to grow.
They grew even faster in the early 1990s, when a tightening oil market drove demand for new technology. This led to breakthroughs in 3D seismology and directional drilling. These breakthroughs allow oil to be sucked economically from far beneath the ocean floor, and out of depleted and formerly abandoned wells.
But such inventions do not come cheap. Schlumberger invests roughly $1 billion a year in research and development, a level it maintained even during the slump after the 2008 financial crisis. That is as much as the mighty ExxonMobil spends; as a share of sales, five times more. The big OFS companies now probably file more patent applications than the oil majors, whose technological skills are largely interpretive. (For example, an oil major may decide where and how to drill based on geophysical data provided by an OFS firm.)
The oil business is likely to grow even more dependent on brainy OFS firms. Global production from mature oilfields is falling by between 2% and 6% a year. In the North Sea it has declined by 6% a year on average since 1999. With global demand for oil growing by 1-2% a year, there are persistent fears of a supply shock. Hence the current high oil prices: even after a 20% fall in recent months, Brent Crude is now around $100 a barrel. Oil firms are searching harder in more remote places, such as the Arctic and the deep seas off Brazil. Operating in such places will require yet more snazzy technology.
With hindsight, the oil companies’ decision to outsource the grubby bits of the job looks like an opportunity squandered. It has also left the oil firms hostage to the availability of increasingly expensive and sought-after services, from advanced drilling to deepwater rigs, which a dwindling number of OFS firms can provide.
There is, at present, still a fair amount of competition in most parts of the services industry. Each big OFS firm has different strengths, and plenty of smaller ones occupy specialised niches. Yet in some areas, especially the geographically remote ones, the demand for complex services often outstrips the supply.
Even worse for the likes of Exxon and BP, this has come at a time when state-owned oil firms have been muscling onto the stage. In the past couple of decades these national oil companies have claimed the best acreage in most old oilfields. The OFS firms have helped them to do so. Where once the state-owned giants hired oil majors to do the work, now they can manage projects themselves and hire technical help directly from the services firms. This can sometimes involve a limited sharing of risk between national and OFS firms, just as in a regular joint venture between oil companies.
Schlumberger, for example, will agree to a measure of payment-for-performance in big contracts. If it can drill more oil from a well than the contract says it must, it charges a higher fee. Other services firms have gone further, taking small equity stakes in exploration projects.
Some analysts wonder how all this might hurt the oil majors. A few decades ago national oil companies had to turn to oil majors for the technology required to get the stuff out of the ground. Today, oilfield service companies offer all the necessary technology and are increasingly willing to take on some of the same risks as an oil company, notes Marcel Brinkman of McKinsey.
Still, it would be wildly premature to bid Exxon adieu. Schlumberger’s performance-based contracts are a long way short of owning reserves—something the company says it will never do. It lacks the mammoth balance-sheet that oil firms maintain to manage the huge risks in oil exploration. It also lacks Exxon’s expertise in managing huge projects. And it is reluctant to annoy its customers by competing with them. Moreover, choosing where and how to explore (another strength of the oil majors) is trickier than you might think.
Instead, Schlumberger is planning more of what it is best at: pushing the technological boundaries of extracting the black stuff. It has recently been busy making acquisitions—including of Smith International, an American drill-bit company, for $11.3 billion—which have given it know-how in most segments of exploration and production. It now hopes to re-engineer the entire process.
The prize of increased efficiencies—delivered in barrels of money, not oil—could be vast. A big deepwater drilling rig costs half a million dollars a day to rent, and can take three months to drill a complicated well. Any OFS company that can shave a few days off that time will be in the money. Drilling is thrilling, and getting more so.

Why Natural Gas

Why Natural Gas – CococoPhillips

Air Land Water
Natural gas is a cleaner-burning fuel with additional environmental benefits over other energy sources when used for electricity and heat production.
Cleaner Burning
Burning natural gas results in very low emissions of nitrogen oxides and sulfur dioxide – reducing acid rain and smog – and virtually no emissions of mercury or particulates (soot), making it among the cleanest ways to generate electricity. Accounting for emissions from fuel production through transportation and conversion, efficient natural gas power plants produce half the carbon dioxide emissions of coal-fired plants.
The modern fleet of U.S. natural gas-fired generating plants operates at just 42 percent of capacity. Utilizing these plants to displace coal-fired power generation is the fastest and most economical path to significant carbon emission reductions. Building and operating new efficient natural gas power plants to replace coal, while reducing carbon dioxide emissions, costs about 40 percent less than new wind generation. Producing electricity from natural gas is highly efficient and requires smaller, less costly pieces of equipment. Also, natural gas does not require the capital equipment and operating costs to reduce air emissions, or the need to dispose of solid waste, that coal-fired plants do.
Other Environmental Benefits
In addition to reduced air emissions, natural gas has other environmental benefits that make it a smart fuel choice. For instance, natural gas-fired power plants use about 60 percent less water than coal plants and 75 percent less water than nuclear power plants for the same electricity output. In addition, natural gas-fired power plants require the least amount of land per megawatt of capacity versus other new power generation options. Wind and solar require 20 times more land to power the same number of homes as a natural gas-fired power plant.
Natural gas for power production avoids some of the challenges facing wind, solar, biofuels and nuclear power generation technologies, such as visual impact, competing land uses, bird strikes and waste disposal. No other electricity generation source can respond as rapidly to fluctuations in U.S. consumer electricity demand as natural gas. Another benefit is that natural gas-fired generation reliably backs up wind- and solar-generated electricity when the wind doesn’t blow and the sun doesn’t shine.
Natural gas is the fastest and most economical path to significantly reducing U.S. emissions of carbon dioxide from power generation, while minimizing our impact on the land and use of our water resources. The many environmental benefits in accelerating the use of natural gas is another reason why we believe natural gas should be an important part of America’s energy future.

Natural Gas Drilling & Completion

Conoco Phillips
Natural Gas Drilling & Completion
Natural gas is found throughout the world in underground formations, such as sandstone, carbonates, coal and shale. Gaining access to the gas involves drilling vertical, horizontal or multi-lateral wells to the target formation. Various completion techniques, such as hydraulic fracturing, are then used to create an effective connection between the well and the targeted hydrocarbon-containing formation, thereby providing a pathway for the gas to be produced.
Before drilling a well, our geologists and engineers complete a full analysis of the geology using proprietary and public data. They assess results from other wells drilled in the vicinity, including water wells, producing oil and gas wells and nonproducing wells (dry wells). A plan is developed for drilling and completing the well that must be approved by state regulators. The company proactively engages key stakeholders, including communities, officials, government agencies and regulators, as plans are being developed.
Many of the steps described are common to all oil and gas well planning and operation efforts, regardless of well design or the formation being targeted for development.
Once a target formation has been identified and appropriate land leases acquired, environmental and regulatory reviews are conducted to assess related environmental impacts. Social and local issues are addressed, and stakeholder engagement commences. The permitting process then begins as prescribed by federal, state and local regulatory requirements.
Before drilling begins ConocoPhillips engineers, geoscientists and environmental employees work with regulatory staffs to collect and analyze information on the geology and surface conditions of the potential drill site. Drilling, surface use and water management plans are developed to maximize natural gas production while protecting the environment and minimizing the well’s overall footprint.
Following the construction of a well pad, a large hole is drilled to a shallow depth. A relatively short length (typically 40 to 120 feet) of large-diameter steel pipe (conductor casing) is set to stabilize the ground at the top of the well.
Drilling continues to a pre-determined depth below the base of usable water. This depth is specified by state or federal regulators for the purpose of protecting potential usable groundwater resources and is based on local geology. While drilling this section, drilling mud – a mixture of fresh water and clay – is pumped into the hole to cool the drill bit, remove any cuttings and create a boundary between the well and surrounding rock.
The drill pipe and drillbit are removed, and a steel casing is inserted. Cement is pumped through the casing, filling the annular space between the outside of the casing and the wellbore. This creates a sealed container that extends from the surface to below the base of freshwater zones. The blowout preventer is then installed at the surface.
Following a series of tests, drilling resumes until it reaches the kick-off point – when a specialized motor is added to the drilling assembly that allows the curved and horizontal sections of the well to be drilled. The kick-off point is typically thousands of feet below any freshwater zones
Once the target depth is reached (based on the length of the horizontal section required), the drilling assembly is removed, and the steel casing is inserted through the entire length of the well. More cement is pumped through the casing, creating another cement-reinforced layer of protection.
Next, a specified length of horizontal casing is perforated to provide a way for natural gas to enter the production casing.
A fluid consisting of water, sand and a small amount of chemicals – some of which can be found in common household and food products – is then injected through the perforations to stimulate gas recovery. The fluid penetrates the shale and creates cracks, or fractures, in the rock. The sand or ceramic particles, called proppant, are carried by the fluid and deposited in the narrow fractures, creating a pathway for gas to reach the well.  This step is called hydraulic fracturing.
A plug is set inside the casing to isolate the stimulated section of the well. The entire perforate-inject-plug cycle is then repeated at regular intervals along the horizontal section of the well. Finally, the plugs are drilled out, allowing the gas and fluids to flow into the wellbore and then up to the surface inside the casing or tubing.
The gas/fluid mixture is separated at the surface, and the fracturing fluid (also known as flowback water) is captured in steel tanks or lined pits. The fracturing fluids are then disposed of via government-approved methods.
The entire well construction process generally takes only two to three months, compared to the 20- to 30-year productive life of a typical well.