Sunday, April 3, 2011

World faces oil supply crunch by 2015, warn British business leaders

LONDON: The world faces an oil supply crunch within the next five years, British business leaders led by Virgin tycoon Richard Branson warned on Wednesday.

The rate at which oil is produced risks hitting a peak by 2015, sparking a surge in crude prices and living costs, said a report from the UK Industry Taskforce on Peak Oil & Energy Security (ITPOES), of which Branson is a member.

The report, entitled 'The Oil Crunch - a wake up call for the UK economy', urged the formation of new organisation to address the issue, with members representing the British government, businesses and consumers.

"The UK Industry Taskforce on Peak Oil and Energy Security (ITPOES) finds that oil shortages, insecurity of supply and price volatility will destabilise economic, political and social activity potentially by 2015," the report said.

"Peak oil refers to the point where the highest practicable rate of global oil production has been achieved and from which future levels of production will either plateau, or begin to diminish.

"This means an end to the era of cheap oil," added the report from the taskforce, whose members include British tycoon Branson and Ian Marchant, head of Scottish & Southern Energy.

ITPOES forecast global oil output would reach a plateau at fewer than 95 million barrels per day potentially by 2015. That compared with 2008 global production of 85 million bpd.

"The taskforce states the impact of peak oil will include sharp increases in the cost of travel, food, heating and retail goods," the report added.

"It finds that the transport sector will be particularly hard hit, with more vulnerable members of society the first to feel the impact."

With Britain facing a national election by June, the grouping also warned that any new government must deal with the looming oil crunch.

"The taskforce warns that the UK must not be caught out by the oil crunch in the same way it was with the credit crunch and states that policies to address peak oil must be a priority for the new government formed after the election."

It added: "Unless we do so, we face a situation during the term of the next government where fuel price unrest could lead to shortages in consumer products and the UK's energy security will be significantly compromised."

Supply-side constraints - lack of construction capacity, oil rigs and skilled manpower - would all contribute towards peak oil, according to the taskforce.

The group also called for the development of alternative methods to powering transport.

Branson, founder of Virgin Group, added that businesses and the government must work alongside each other.

"Working together, we must ensure that the government takes action to address the impact of the oil crunch and ensure the UK is better prepared to withstand higher and more volatile oil prices," Branson said.

"UK competitiveness will be hampered unless we can develop viable, affordable and secure long term sources of alternative energy."

In recent years, oil prices have been extremely volatile, spiking to record heights above 147 dollars per barrel in July 2008, before plunging to 32 dollars per barrel as a global recession slammed energy demand.

World oil prices have since recovered ground to trade between 70-80 dollars as the market was boosted by signs of global economic recovery. - AFP/de

Saturday, March 12, 2011

Expandable Sand screens

The Open-hole applications testing multi-zone completions, expandable tools to new limits.

Completions have never been simple. But for today’s wells, the industry has had to push the envelope to develop game-changing technologies to operate in increasingly complex environments while reducing rig time, performing downhole functions in a single trip of the workstring and addressing the critical issue of sand control. Multi-zone completion technologies, along with expandable tools, are increasingly being deployed in nearly every arena worldwide, from long land horizontals to shale and tight gas to the deepest waters.
“The days where an operator drills one well to target one specific zone is becoming more the exception than the norm,” said Bryan Stamm, technical manager,Schlumberger Sand Management Division. “As technologies for multi-zone completions become more and more mainstream, whether for stacked, single-trip multi-zone, multi-stage fracturing or intelligent completions, we’re starting to see the industry become more comfortable with this approach.”
In cased holes, where multi-zone technology is more mature, the emphasis has been on efficiency, using packers and perforations to produce each zone, Mr Stamm continued.
“When it comes to open hole, I would say that is where the industry has faced some very rapid advancements in recent years, driven mainly by advances in horizontal drilling,” he said. Historically, sand-prone open-hole reservoirs could be completed only in one zone using a gravel packing technique, he noted. Multi-zone completions can now be accomplished with stand-alone sand screens.....(Click here)

Sunday, February 13, 2011

looking for Career in oil and gas industry?

Job Openings to Asian

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Friday, January 7, 2011

Japan Will Drill for Methane Off Its Shores

September 27, 2010, 2:30 PM

Japan will attempt to tap frozen methane gas deposits off its southeast coast by drilling a series of deep-sea test wells early next year, the Guardian newspaper reported on Monday.

The project will assess the commercial viability of tapping the deposits, called methane hydrates, which lie below thousands of feet of seawater and sediment. The drilling will be done by the Japan Oil, Gas and Metals National Corporation, in association with the Japanese government. The Japanese Ministry of Trade has requested more than $1 billion for the project, slated to begin in the spring.

Methane hydrates form in cold, high-pressure environments and are found throughout the world’s oceans and beneath the frozen ground of high-latitude countries. Methane is a clean-burning fuel, but is also a powerful greenhouse gas, with roughly 21 times the heat-trapping potential of carbon dioxide.

The energy content of the Earth’s methane hydrates — sometimes called “fire ice” or “ice that burns” — is vast, possibly greater than that of all other fossil fuels combined, according to the United States Department of Energy.

The gas deposits have yet to be tapped successfully on a commercial scale, but Japan, which lacks much in the way of domestic energy supplies and imports more than 99 percent of its oil, is at the forefront of efforts to do so.

In 2008, Japanese engineers extracted methane from hydrate deposits nearly a mile beneath the Canadian tundra, in what was hailed as a major breakthrough in the field. The Japanese government has declared its intention to commercially tap methane hydrates by 2018.

India and China have discovered huge frozen methane deposits off their own coasts, and both countries are seeking ways to develop the finds into commercially exploitable energy sources.

The environmental risks posed by undersea hydrates alarm some scientists and environmentalists, however. Potential dangers involve inadvertently setting off undersea landslides, which could wipe out nearby seafloor life, and uncontrollable methane leaks from destabilized gas and hydrate formations.

Massive eruptions of methane gas from melting or collapsing undersea hydrates have occurred naturally in the distant past as a result of rapid climate warming, studies have shown.

Yet engineers involved in the hydrate exploration projects and some energy experts discount the possibility that drilling could trigger massive accidental releases of methane.

“Can environmental disaster happen by gas hydrate production? The answer is no,” Koji Yamamoto, a project director for the Japan Oil, Gas and Metals National Corporation, told The Asia Times in December 2009.

Saturday, December 18, 2010

Halliburton 2010 GeoTap® IDS Sensor

This is the Halliburton Sperry Drilling 2010 spotlight on new technology.

To obtain fluid samples while drilling the well. Only available on wireline before, formation fluid sampling is now possible using LWD technology. The GeoTap® IDS sensor revolutionizes the industry by allowing downhole capture, identification and surface recovery of representative fluid samples on LWD. Built on the acclaimed GeoTap® formation pressure tester platform, the GeoTap IDS sensor delivers real-time reservoir characterization and helps eliminate the time and cost of wireline sampling.

GeoTap IDS Sensor Benefits:-
-Can reduce uncertainly in complex reservoirs
-Helps improve economic performance in high-cost deepwater environments
-Can eliminate costly wireline trips and associated rig time
-Get data within hours, not days, through reduced pump-out time
-Improve geo-correlation accuracy and geosteering capabilities

one trip down to the hole to get reservoirs data in realtime save time which is equal to save money, an innovative product also a value added product.


GeoTap® Sensor
With Sperry Drilling services' GeoTap® LWD formation tester, it is possible to obtain real-time direct pore pressure measurements, with accuracy and precision comparable to that of wireline formation testers. The GeoTap service bridges a critical gap in drilling safety and optimization, providing early and reliable measurements of reservoir pressure and mud density.

Helps improve formation evaluation.
-Obtain real-time fluid gradients and fluid mobility (permeability/viscosity indicator)
-Identify fluid contact points, and determine reservoir connectivity/compartmentalization, and depletion

Can increase safety of operation.
-Determine optimal mud weight and manage equivalent circulating density
-Know of pressure changes when they occur, not after it's too late
-Continuously update wellbore stability assessments
-Reduce formation damage

Helps increase drilling efficiency.
-Determine precise overbalance for maximizing ROP
-Continuously monitor hole cleaning effectiveness with Pressure-While-Drilling, while reducing formation damage due to swab/surge
Save time, money
reduce rig down time associated with wireline testing

Friday, November 5, 2010

Swell Packer by Easy Well Solutions

Swell Packer enables water control in open hole. Reliable and permanent annular isolation is normally required to enable water control in open hole completed wells. The Swell Packer, supplied by Easy Well Solutions is an annular isolation packer expanding and sealing in contact with hydrocarbons. Installation does not require any operations or manipulation. This saves rig time and increases reliability. The Swell Packer is installed across a formation barrier and left in place. It can be used for open hole and cased hole and is available for non-standard casing sizes.

In a mature North Sea field, North Cormorant, operated by Shell UK a through tubing drilling campaign was ongoing. The operations required zonal isolation from along the reservoir due to multiple intermittent layers with water and oil. Cementing these reservoirs was a challenge because of the small pipe diameters, ambitious drilling targets and high pressure contrasts. The operator performed a detailed analysis and found that Swell Packer would enhance the operations. No problems were associated with the installation. The packers provided better zonal isolation properties than cement. Perforating was avoided. By simplifications of the well design, the system has saved close to 50 percent of the total well cost.

In a shallow, viscous oil development in Alaska, U.S., an operator drilled multilateral wells to drain four zones. The bottom lateral was drilled undulating between two zones with five penetrations of the mudstone separating the zones. Previous wells have been plugged within a month after onset of production. To avoid this mudstone to mobilize and spread to plug adjacent slotted liner, a Swell Packer was positioned just above and just below each of these mudstone intervals. No plugging related production impairment has been seen in these wells.

To date, more than 250 Swell Packers have been installed in a multitude of downhole environments in different areas of the world. The installations has been with water control, open hole fracturing, sand control and many different applications. All installed packers have performed to expectation and no sealing failure has been detected.

Halliburton Swell packer link:-

Baker Oil Tools' REPacker™
Reduce operational, HSE, and wellbore damage risks; cut overall cost
We offer several types of reactive element packers that are triggered by contact with well fluids. Our packers will cut your overall costs and reduce HSE and wellbore damage risks.
Our Baker Oil Tools' REPacker™ is a self-energizing, reactive-element, swelling-elastomer packer that provides a long-term barrier to annular flow around tubular assemblies in either open or cased-hole. No cement is required. It is ideal for deviated wells.

The highly reliable packer has no moving parts and is available in oil- and water-reactive, non-reversible elements. There is no risk of elastomer shrinkage if fluids are changed after swelling. Deployment and installation are simple and do not require running tools or specialized personnel.
The packer is a sealing device built on a casing pup that matches the mechanical properties of the liner. The activation methods for annular sealing are the swelling properties of the rubber element reacting with wellbore fluids. This packer can be used in openhole or perforated casing to isolate unwanted formation production.

The FORMpac™ expandable packer with reactive element technology eliminates annular flow around liner assemblies. It is a sealing device built on expandable solid pipe technology. The primary activation method for annular sealing is expansion of the solid pipe mandrel. The secondary activation method is the swelling properties of rubber in all hydrocarbons except very lean, single phase gas. This thermodynamic absorption expansion is continuous.

The tool can be used in openhole or perforated casing to isolate unwanted formation or production. The FORMpac packer provides a simple and effective method to eliminate the linear annular flow of fluids in cased and open holes with maximum pass-through ID. It will isolate troublesome shale in openhole completions. The packer can be used with both standard and expanding liners and sand control screens.

Our RCPacker is used in openhole wells to isolate unwanted formation production. When used together with our EQUALIZER™ inflow control device, it can efficiently manage flow in the annulus. The reactive core (RC) packer uses non-cement inflation media for permanent isolation in openhole completions.

A swelling reactive core is protected by an inflatable element. The initial seal provided by the inflatable element is less affected by downhole pressure and temperature changes after the core of the packer system has reacted with its inflation fluid. The element uses our XTremeZone™ technology for enhanced run-in capabilities, along with internal metal reinforcing on either end to provide high differential capability.

The REBarrier uses a self-energizing swelling elastomer to reduce the annular flow of fines and other wellbore debris in open or cased-hole. The packer is a sealing device built on a substrate that can be easily installed on your casing. The activation methods for annular sealing are the swelling properties of the rubber element reacting with the wellbore fluids.
Our REFlex™ field-installable reactive element packer is installed onto nominal API base pipe. The primary purpose of the tool is to add flexibility in deployment and further simplify your completions. The REFlex packer is built with a rigid steel cage that is surrounded by a proprietary Baker Hughes reactive element rubber matrix.

Expandable Liner Hanger System

Liner systems
The Baker Hughes TORXS™ liner hanger system is the only expandable liner hanger system that can be run and installed conventionally, without requiring a critically timed high-pressure plug bump as the primary activation method for the hanger or packer, or for release of the running tool.
TORXS eliminates dependence on a plug bump, because all hydraulic activations, including tool release, occur with pressure acting on a positive seal in the running tool. This minimizes the risk of poor quality liner to cement bonding that can occur when a liner is ballooned with a highpressure plug bump.

The TORXS liner system—run on the TORXS liner running tool—can be run the same as any Baker Hughes premium liner system.

Upon reaching setting depth, the liner can be circulated and conditioned. A setting ball is dropped from the surface and landed on the extrudable ball seat in the running tool. Applied pressure actuates the hydraulic anchor along with the swage mechanism on the running tool causing the hanger body and slips to expand outward making permanent contact to the casing string. Circulation is again established and cementing of the liner can be performed.

This is Halliburton Expandable Liner Hanger link.

Sunday, October 31, 2010

News:- Double Blow for American Oil Dependency Hopes

Article From

The last few days have seen a double blow to American hopes for reducing its heavy dependence on imported oil.

1st, on Tuesday the U.S. Geological Survey cut by 90% its estimate of the undiscovered hydrocarbon reserves beneath the National Petroleum Reserve on Alaska’s North Slope–the richest region for onshore oil production in the country.

2nd, one of the largest oil and gas producers in the American, Royal Dutch Shell, revealed that the Deepwater Horizon accident and subsequent drilling moratorium will significantly reduce for several years its oil output from the Gulf of Mexico–the richest offshore area in the American It also unveiled its third quarter results.

Already unrealistic hopes that the American could mitigate the profound economic and security implications of weaning itself off foreign oil by dramatically boosting domestic output are more remote than ever.

The news from Alaska is actually even worse than its seems on first reading. The USGS cut its oil reserve estimate for the NPRA from 10.6 billion barrels of oil to 896 million barrels, because new wells show that much of what was assumed to be oil reservoirs in fact contain gas, which has a lower energy content.

Of course, gas reserves have value, but their development can be very difficult to justify in such remote locations. Two major Alaska oil producers, ConocoPhillips and BP, have been debating for years how to monetize the huge gas reserves they hold in North Slope oil fields, but have so far failed to find an economic solution. Their plans to build a $35 billion pipeline to carry the gas to towns and cities in the lower 48 states are being reassessed and may never come to pass.

The reappraisal of the NPRA also raises questions about how much oil really lies beneath the perennial bargaining chip in the contest between environmentalism and energy security, the Arctic National Wildlife Refuge.

On Thursday, Shell revealed that the moratorium on drilling imposed on the Gulf of Mexico in the wake of the Deepwater Horizon disaster will have an impact on its ability to produce oil from the region for several years.

The company’s output is already 10,000 barrels of oil equivalent (boe) a day lower than it would have been without the moratorium, because it has been prevented from doing development drilling to boost output at existing fields. That shortfall will be at least 40,000 boe a day in 2011, a fall of 15% from the expected level, and could rise further because of anticipated delays in the issuance of new permits now that the moratorium has been lifted, said Shell’s Chief Financial Officer Simon Henry.

Other companies have yet to disclose whether they will also suffer a 15% cut in their potential production from the region, but everyone has suffered similar effects from the moratorium.

The impact of this on the American economy could be profound. The Gulf of Mexico produced 1.6 million barrels of oil a day in 2009, almost 30% of total American crude oil production.

Shell’s operations in Alaska have also taken a hit. Its plans to drill in the promising Beaufort Sea off Alaska’s north slope are on hold for at least 12 months after permits to drill this year were withdrawn after the Deepwater Horizon disaster. Applications have been resubmitted, but the process may take longer than expected, Henry said.

Shell has not even resubmitted its even more contentious applications to drill in the neighboring Chukchi Sea.

The prospects of a dramatic boost in domestic American oil production look slimmer by the day. If the country is serious in its intention to wean itself off foreign oil, it’s time to switch the focus from billion-barrel reserves to miles per gallon.

Saturday, October 16, 2010

Blowout preventer

Cameron Int'l Corporation's EVO Ram BOP Drawing.

Hydril Annular BOP Drawing.

Blowout preventer

The blow-out preventer is a large, specialized valve used to seal, control & monitor oil and gas wells. Blow-out preventers were developed for coping with extreme erratic pressures and uncontrolled flow (formation kick) emanating from a well reservoir during drilling. Kicks can lead to a potentially catastrophic event known as a blow-out. In addition to controlling the down-hole (occurring in the drilled hole) pressure and the flow of oil and gas, blow-out preventers are intended to prevent tubing (e.g. drill pipe and well casing), tools and drilling fluid from being blown out of the wellbore (also known as bore hole, the hole leading to the reservoir) when a blow-out threatens. blow-out preventers are critical to the safety of crew, rig (the equipment system used to drill a wellbore) and environment, and to the monitoring and maintenance of well integrity; thus blow-out preventers are intended to be fail-safe devices.

That term BOP (an initialism rather than spoken as a word, i.e.- pronounced 'B' 'O' 'P') is used in oilfield vernacular to refer to blow-out preventers.
The abbreviated term preventer, usually prefaced by a type (e.g. ram preventer), is used to refer to a single blow-out preventer unit. A blow-out preventer may also simply be referred to by its type (e.g. ram).
The terms blow-out preventer, blow-out preventer stack and blow-out preventer system are commonly used interchangeably and in a general manner to describe an assembly of several stacked blow-out preventers of varying type and function, as well as auxiliary components. A typical subsea deepwater blow-out preventer system includes components such as electrical and hydraulic lines, control pods, hydraulic accumulators, test valve, kill and choke lines and valves, riser joint, hydraulic connectors, and a support frame.
Two categories of blow-out preventer are most prevalent: ram and annular. BOP stacks frequently utilize both types, typically with at least one annular BOP stacked above several ram BOPs.
(A related valve, called an inside blow-out preventer, internal blow-out preventer, or IBOP, is positioned within, and restricts flow up, the drillpipe. This article does not address inside blow-out preventer use.)
blow-out preventers are used at land and offshore rigs, and subsea. Land and subsea BOPs are secured to the top of the wellbore, known as the wellhead. BOPs on offshore rigs are mounted below the rig deck. Subsea BOPs are connected to the offshore rig above by a drilling riser that provides a continuous pathway for the drill string and fluids emanating from the wellbore. In effect, a riser extends the wellbore to the rig.

Use of blow-out preventer:-
The invention of blow-out preventers was instrumental in reducing the incidence of oil gushers, blow-outs, which are dangerous and costly.
blow-out preventers come in a variety of styles, sizes and pressure ratings. Several individual units serving various functions are combined to compose a blow-out preventer stack. Multiple blow-out preventers of the same type are frequently provided for redundancy, an important factor in the effectiveness of fail-safe devices.

The primary functions of a blow-out preventer system are to

Confine well fluid to the wellbore;
Provide means to add fluid to the wellbore;
Allow controlled volumes of fluid to be withdrawn from the wellbore.

Additionally, and in performing those primary functions, blow-out preventer systems are used to:

Regulate and monitor wellbore pressure;
Center and hang off the drill string in the wellbore;
Shut in the well (e.g. seal the void, annulus, between drillpipe and casing);
“Kill” the well (prevent the flow of formation fluid, influx, from the reservoir into the wellbore) ;
Seal the wellhead (close off the wellbore);
Sever the casing or drill pipe (in case of emergencies).

In drilling a typical high-pressure well, drill strings are routed through a blow-out preventer stack toward the reservoir of oil and gas. As the well is drilled, drilling fluid, “mud,” is fed through the drill string down to the drill bit, “blade,” and returns up the wellbore in the ring-shaped void, annulus, between the outside of the drill pipe and the casing (piping that lines the wellbore). The column of drilling mud exerts downward hydrostatic pressure to counter opposing pressure from the formation being drilled, allowing drilling to proceed.

When a kick (influx of formation fluid) occurs, rig operators or automatic systems close the blow-out preventer units, sealing the annulus to stop the flow of fluids out of the wellbore. Denser mud is then circulated into the wellbore down the drill string, up the annulus and out through the choke line at the base of the BOP stack through chokes (flow restrictors) until down-hole pressure is overcome. Once “kill weight” mud extends from the bottom of the well to the top, the well has been “killed”. If the integrity of the well is intact drilling may be resumed. Alternatively, if circulation is not feasible it may be possible to kill the well by "bullheading", forcibly pumping, in the heavier mud from the top through the kill line connection at the base of the stack. This is less desirable because of the higher surface pressures likely needed and the fact that much of the mud originally in the annulus must be forced into receptive formations in the open hole section beneath the deepest casing shoe.

If the blow-out preventers and mud do not restrict the upward pressures of a kick, a blow-out results, potentially shooting tubing, oil and gas up the wellbore, damaging the rig, and leaving well integrity in question.
Since BOPs are important for the safety of the crew and natural environment, as well as the drilling rig and the wellbore itself, authorities recommend, and regulations require, that BOPs be regularly inspected, tested and refurbished. Tests vary from daily test of functions on critical wells to monthly or less frequent testing on wells with low likelihood of control problems.

Exploitable reservoirs of oil and gas are increasingly rare and remote, leading to increased subsea deepwater well exploration and requiring BOPs to remain submerged for as long as a year in extreme conditions. As a result, BOP assemblies have grown larger and heavier (e.g. a single ram-type BOP unit can weigh in excess of 30,000 pounds), while the space allotted for BOP stacks on existing offshore rigs has not grown commensurately. Thus a key focus in the technological development of BOPs over the last two decades has been limiting their footprint and weight while simultaneously increasing safe operating capacity.

Wednesday, September 15, 2010

What Is Fracking or hydraulic fracturing?

A controversial process for extracting natural gas from shale, is drawing criticism as opponents question what effects pumping thousands of gallons of water and chemicals underground will have.

The Christian Science Monitor reported that public hearings being held in Binghamton, N.Y., drew hundreds of protesters on Monday. The hearings are part of the Environmental Protection Agency's investigation into how fracking affects people and the environment.
The EPA explained that hydraulic fracturing is a process used to extract underground resources such as oil, natural gas and geothermal energy. It involves the pressurized injection of water and chemical additives into a geologic formation in hopes that the pressure is enough to exceed the strength of the rock and enlarge fractu

res in it.

"Propping agents" s

uch as sand or ceramic beads are pumped into the fractures to keep them open and pumping pressure is released as the fracturing fluids return to the surface. Natural gas will then flow from pores and fractures in the rock into a well that will extract more.

The EPA is attempting to determine whether, among other concerns, there could be any effects on drinking water supplies. reported that the hearings have drawn strong views on both sides. Those against it hope that the

EPA study will prove that fracking is an environmental danger that needs to be regulated or banned by the federal government.

Rep. Maurice Hinchey (D-N.Y.), said fracking has been linked to "numerous reports of water contamination" nationwide.

The gas industry fears new restrictions could impair the industry which it said is one of the few current economic bright spots in and around Pennsylvania.

"Now is especially not the time to furthe

r limit energy-job opportunities for those in need," John Harmon of the African American Chamber of Commerce testified at a hearing.


Since the pay zone is sealed off by the production string and cement, perforations must be made in order for the oil or gas to flow into the wellbore. Perforations are simply holes that are made through the casing and cement and extend some distance into the formation. The most common method of perforating incorporates shaped-charge explosives (similar to those used in armor-piercing

shells). Shaped charges accomplish penetration by creating a jet of high-pressure, high-velocity gas. The charges are arranged in a tool called a gun that is lowered into the well opposite the producing zone. Usually the gun is lowered in on wireline (1). When the gun is in position, the charges are fired by electronic means from the surface (2). After the perforations are made, the tool is retrieved (3). Perforating is usually performed by a service company that specializes in this technique.


Sometimes, however, petroleum exists in a formation but is unable to flow readily into the well because the formation has very low permeability. If the formation is composed of rocks that dissolve upon being contacted by acid, such as limestone or dolomite, then a technique known as acidizing may be required. Acidizing is usually performed by an acidizing service company and may be done before the rig is moved off the well; or it can also be done after the rig is moved away. In any case, the acidizing operation basically consists of pumping anywhere from fifty to thousands of gallons of acid down the well. The acid travels down the tubing, enters the perforations, and contacts the formation. Continued pumping forces the acid into the formation where it etches channels – channels that provide a way for the formation’s oil or gas to enter the well through the perforations.


When sandstone rocks contain oil or gas in commercial quantities but the permeability is too low to permit good recovery, a process called fracturing may be used to increase permeability to a practical level. Basically, to fracture a formation, a fracturing service company pumps a specially blended fluid down the well and into the formation under great pressure. Pumping continues until the formation literally cracks open. Meanwhile, sand, walnut hulls, or aluminum pellets are mixed into the fracturing fluid. These materials are called proppants. The proppant enters the fractures in the formation, and, when pumping is stopped and the pressure allowed to dissipate, the proppant remains in the fractures. Since the fractures try to close back together after the pressure on the well is released, the proppant is needed to hold or prop the fractures open. These propped-open fractures provide passages for oil or gas to flow into the well. See figure to the right.

Saturday, August 21, 2010

Electric Submersible Pumping system (ESP) - weatherford

There is a number of company come out the ESP, that is Electric Submersible Pumping system from Weatherford, Baker huge, Schlumberger, Halliburton and BJ Services.

ESP is in secondary plan for recovery oil.

The link here is a web site from baidu's document upload that shown Halliburton BDMI on ESP.

Gas Lift Technology

Gas Lift is also used in secondary recovery, the video below will show you how weatherford do it.

Gas lift valve is used to releasing of CO2 that make the Oil lighter (to make oil density lighter by gas lift method, because gas is lighter than Oil in density will help to get the oil float to the surface)

Oil and Gas Recovery Demonstration (The secondary recovery plan.)

The secondary recovery plan.

This video will show you how the oil and gas recovery is done by injecting Gas (CO2) and water.

There is other recovery that used only brine water injection or "water injection" for recovery oil and gas where the remaining oil and gas in the well left about 40% or less that are difficult to recover by conventional completion equipment.

This type of secondary recovery plan will be deploy until the well is fully depleted that unable to recover anymore of oil and gas.

What is "well completion"?

A Well completion need a number of equipments/devices to joint in a series to form a Well completion string and run down in hole for oil production or oil recovery.

Those equipments sometime needed running tool / puuling tool to run, pulled or set the packer
(Equipment that like production permanent packer, lock mandrel, Sliding side door (SSD) and some other locking device that used in well.)

who are those Well completion companies?

company like:- smith international, Baker huge, Halliburton, Schlumberger, Weatherford and BJ services

How the Oil and Gas well been drill?

This video will tell you how the oil and gas well been drill.

Saturday, July 19, 2008


Nanosolar is a global leader in solar power innovation. They are setting the standard for affordable green power with solar cell technology of distinctly superior cost efficiency, versatility, and availability.

Their mission is very simple: Delivering cost-efficient solar electricity.
Leveraging recent science in nanostructured materials, we have developed a critical mass of engineering advances that profoundly change the cost efficiency and production scalability of solar electricity cells and panels.

Their first product, the Nanosolar Utility Panel™ enables unprecedented system economics at utility scale.

Founded in 2002, They are building the world's largest solar cell factory in California and the world's largest panel-assembly factory in Germany.

Nanosolar's 140,000 sqft facility in San Jose, California

Nanosolar's 507,000 sqft manufacturing site near Berlin, Germany

Water Fuel Technology

Project Energy - Water Fuel

Water Fuel Car

Salt Water Fuel

Picken's Plan

T. Boone Pickens, founder and chairman, BP Capital Management, is principally responsible for the formulation of the energy futures investment strategy of the BP Capital Commodity Fund and the BP Capital Equity Fund. With more than $4 billion under management, BP Capital manages one of the nation’s most successful energy-oriented investment funds. Pickens frequently utilizes his wealth of experience in the oil and gas industry in the evaluation of potential equity investments and energy sector themes. He has not been shy in predicting oil and gas prices and — more often than not — has been uncannily accurate.

Pickens is also aggressively pursuing a wide range of other business interests, from water marketing and ranch development initiatives to Clean Energy, a company he founded and is the largest shareholder. Through Mesa Water, Pickens is the largest private holder of permitted groundwater rights in the United States. Clean Energy is advancing the use of natural gas as a cleaner-burning and more cost-effective transportation fuel alternative to gasoline and diesel.

Boone grew up in Holdenville, a small eastern Oklahoma town. His father was in the oil business, and his mother ran the Office of Price Administration during World War II, rationing gasoline and other goods for four counties. Boone attributes much of his success to his mother and father.

Boone graduated as a geologist from Oklahoma State University in 1951 and started work with Phillips Petroleum Co. in Bartlesville, Oklahoma. After three and a half years, he struck out on his own as an independent geologist. Pickens was founder of Mesa Petroleum in its various forms beginning in 1956. Mr. Pickens’ career at Mesa spanned four decades. Under his leadership, Mesa grew to become one of the largest and most well known independent exploration and production companies in the United States; Mesa produced more than 3 trillion cubic feet of gas and 150 million barrels of oil from 1964 to 1996.

From its inception, Mesa was at the forefront of change and innovation. Mesa's fitness program is a good example. Boone has long understood the benefits of physical fitness. Mesa's fitness program has become a model for corporate America, and Mesa was the first company to be accredited by the Institute for Aerobics Research.

Throughout his professional life, Pickens has been a generous philanthropist, giving away almost one half of a billion dollars. In 2006, he contributed $175 million to a wide range of causes and the formation of the T. Boone Pickens Foundation. He has appeared multiple times on The Chronicle of Philanthropy’s list of top U.S. philanthropists. The T. Boone Pickens Foundation is improving lives through grants supporting educational programs, medical research, athletics and corporate wellness, at-risk youth, the entrepreneurial process, and conservation and wildlife initiatives.

The Horatio Alger Association of Distinguished Americans Inc. selected Pickens as a recipient of the 2006 Horatio Alger Award, which epitomizes those who overcome adversity and humble beginnings to achieve success. It is but one of many honors awarded to Pickens for his achievements, including Trader Monthly’s 2006 Trader of the Year award, the Texas Business Hall of Fame, and the Oklahoma Hall of Fame.

Pickens lives in Dallas and is married to Madeleine Ann Pickens. He has five children and 12 grandchildren.

Saturday, March 29, 2008

What is Fusion power?

Internal view of the JET tokamak superimposed with an image of a plasma taken with a visible spectrum video camera. © EFDA-JET

Fusion Power maybe the next generation power source for man kind. Plasma is very useful in this Fusion Power, it shield the heat from the nuclear fusion.

Fusion power refers to power generated by nuclear fusion reactions. In this kind of reaction, two light atomic nuclei fuse together to form a heavier nucleus and in doing so, release energy. In a more general sense, the term can also refer to the production of net usable power from a fusion source, similar to the usage of the term "steam power." Most design studies for fusion power plants involve using the fusion reactions to create heat, which is then used to operate a steam turbine, similar to most coal-fired power stations as well as fission-driven nuclear power stations.

The largest current experiment is the Joint European Torus [JET]. In 1997, JET produced a peak of 16.1 MW of fusion power (65% of input power), with fusion power of over 10 MW sustained for over 0.5 sec. In June 2005, the construction of the experimental reactor ITER, designed to produce several times more fusion power than the power put into the plasma over many minutes, was announced. The production of net electrical power from fusion is planned for DEMO, the next generation experiment after ITER.

Fuel cycle
The basic concept behind any fusion reaction is to bring two or more atoms very close together, close enough that the strong nuclear force in their nuclei will pull them together into one larger atom. If two light nuclei fuse, they will generally form a single nucleus with a slightly smaller mass than the sum of their original masses. The difference in mass is released as energy according to Einstein's mass-energy equivalence formula E = mc². If the input atoms are sufficiently massive, the resulting fusion product will be heavier than the reactants, in which case the reaction requires an external source of energy. The dividing line between "light" and "heavy" is iron. Above this atomic mass, energy will generally be released in nuclear fission reactions, below it, in fusion.

The Sun is a natural fusion reactor.

Fusion between the atoms is opposed by their shared electrical charge, specifically the net positive charge of the nuclei. In order to overcome this electrostatic force, or "Coulomb barrier", some external source of energy must be supplied. The easiest way to do this is to heat the atoms, which has the side effect of stripping the electrons from the atoms and leaving them as bare nuclei. In most experiments the nuclei and electrons are left in a fluid known as a plasma. The temperatures required to provide the nuclei with enough energy to overcome their repulsion is a function of the total charge, so hydrogen, which has the smallest nuclear charge therefore reacts at the lowest temperature. Helium has an extremely low mass per nucleon and therefore is energetically favoured as a fusion product. As a consequence, most fusion reactions combine isotopes of hydrogen ("protium", deuterium, or tritium) to form isotopes of helium (³He or 4He).
Perhaps the three most widely considered fuel cycles are based on the D-T, D-D, and p-11B reactions. Other fuel cycles (D-³He and ³He-³He) would require a supply of ³He, either from other nuclear reactions or from extraterrestrial sources, such as the surface of the moon or the atmospheres of the gas giant planets. The details of the calculations comparing these reactions can be found here.

Diagram of the D-T reaction

D-T fuel cycle
Diagram of the D-T reaction
The easiest (according to the Lawson criterion) and most immediately promising nuclear reaction to be used for fusion power is:

D + T4He + n

Deuterium is a naturally occurring isotope of hydrogen and as such is universally available. The large mass ratio of the hydrogen isotopes makes the separation rather easy compared to the difficult uranium enrichment process. Tritium is also an isotope of hydrogen, but it occurs naturally in only negligible amounts due to its radioactive half-life of 12.32 years. Consequently, the deuterium-tritium fuel cycle requires the breeding of tritium from lithium using one of the following reactions:

n + 6Li → T + 4He
n + 7Li → T + 4He + n

The reactant neutron is supplied by the D-T fusion reaction shown above, the one which also produces the useful energy. The reaction with 6Li is exothermic, providing a small energy gain for the reactor. The reaction with 7Li is endothermic but does not consume the neutron. At least some 7Li reactions are required to replace the neutrons lost by reactions with other elements. Most reactor designs use the naturally occurring mix of lithium isotopes. The supply of lithium is more limited than that of deuterium, but still large enough to supply the world's energy demand for thousands of years.
Several drawbacks are commonly attributed to D-T fusion power:
It produces substantial amounts of neutrons that result in induced radioactivity within the reactor structure.
Only about 20% of the fusion energy yield appears in the form of charged particles (the rest neutrons), which limits the extent to which direct energy conversion techniques might be applied.

The use of D-T fusion power depends on lithium resources, which are less abundant than deuterium resources.
It requires the handling of the radioisotope tritium. Similar to hydrogen, tritium is extremely difficult to contain and is expected to leak from reactors in some quantity. Estimates suggest that this would represent a fairly large environmental release of radioactivity.[1]
The neutron flux expected in a commercial D-T fusion reactor is about 100 times that of current fission power reactors, posing problems for material design. Design of suitable materials is underway but their actual use in a reactor is not proposed until the generation after ITER. After a single series of D-T tests at JET, the largest fusion reactor yet to use this fuel, the vacuum vessel was sufficiently radioactive that remote handling needed to be used for the year following the tests.
On the other hand, the volumetric deposition of neutron power can also be seen as an advantage. If all the power of a fusion reactor had to be transported by conduction through the surface enclosing the plasma, it would be very difficult to find materials and a construction that would survive, and it would probably entail a relatively poor efficiency.

D-D fuel cycle
Though more difficult to facilitate than the deuterium-tritium reaction, fusion can also be achieved through the reaction of deuterium with itself. This reaction has two branches that occur with nearly equal probability:

D + D → T + p

→ ³He+ n

The optimum temperature for this reaction is 15 keV, only slightly higher than the optimum for the D-T reaction. The first branch does not produce neutrons, but it does produce tritium, so that a D-D reactor will not be completely tritium-free, even though it does not require an input of tritium or lithium. Most of the tritium produced will be burned before leaving the reactor, which reduces the tritium handling required, but also means that more neutrons are produced and that some of these are very energetic. The neutron from the second branch has an energy of only 2.45 MeV, whereas the neutron from the D-T reaction has an energy of 14.1 MeV, resulting in a wider range of isotope production and material damage. Assuming complete tritium burn-up, the reduction in the fraction of fusion energy carried by neutrons is only about 18%, so that the primary advantage of the D-D fuel cycle is that tritium breeding is not required. Other advantages are independence from limitations of lithium resources and a somewhat softer neutron spectrum. The price to pay compared to D-T is that the energy confinement (at a given pressure) must be 30 times better and the power produced (at a given pressure and volume) is 68 times less.

p-11B fuel cycle
If aneutronic fusion is the goal, then the most promising candidate may be the proton-boron reaction:

p + 11B → 3 4He

Under reasonable assumptions, side reactions will result in about 0.1% of the fusion power being carried by neutrons. At 123 keV, the optimum temperature for this reaction is nearly ten times higher than that for the pure hydrogen reactions, the energy confinement must be 500 times better than that required for the D-T reaction, and the power density will be 2500 times lower than for D-T. Since the confinement properties of conventional approaches to fusion such as the tokamak and laser pellet fusion are marginal, most proposals for aneutronic fusion are based on radically different confinement concepts

History of research
The idea of using human-initiated fusion reactions was first made practical for military purposes, in nuclear weapons. In a hydrogen bomb, the energy released by a fission weapon is used to compress and heat fusion fuel, beginning a fusion reaction which can release a very large amount of energy. The first fusion-based weapons released some 500 times more energy than early fission weapons.
Civilian applications, in which explosive energy production must be replaced by a controlled production, are still being developed. Although it took less than ten years to go from military applications to civilian fission energy production,[2] it was very different in the fusion energy field, more than fifty years having already passed[3] without any energy production plant being started up

Saturday, November 24, 2007

What is Gas Hydrate?

A gas hydrate is a crystalline solid; its building blocks consist of a gas molecule surrounded by a cage of water molecules. Thus it is similar to ice, except that the crystalline structure is stabilized by the guest gas molecule within the cage of water molecules. Many gases have molecular sizes suitable to form hydrate, including such naturally occurring gases as carbon dioxide, hydrogen sulfide, and several low-carbon-number hydrocarbons, but most marine gas hydrates that have been analyzed are methane hydrates.

Gas Hydrates will be the coming future generation new source of energy.

It also called Natural Gas Hydrates.

some even called Clathrate hydrate.

Clathrate hydrates (or alternatively gas clathrates, gas hydrates, clathrates, hydrates etc) are a class of solids in which gas molecules occupy "cages" made up of hydrogen-bonded water molecules. These "cages" are unstable when empty, collapsing into conventional ice crystal structure, but they are stabilized by the inclusion of appropriately sized molecules within them. Most low molecular weight gases (including O2, H2, N2, CO2, CH4, H2S, Ar, Kr, and Xe), as well as some higher hydrocarbons and freons will form hydrate under certain pressure-temperature conditions. Clathrate hydrates are not chemical compounds. The formation and decomposition of clathrate hydrates are first order phase transitions, not chemical reactions.

Clathrates are believed to occur in large quantities on some outer planets, moons and trans-Neptunian objects, binding gas at fairly high temperatures. Clathrates have also been discovered in large quantity on Earth, e.g. in giant natural methane clathrate deposits on the deep ocean floor (e.g. in the northern headwall flank of the Storegga Slide, which is a part of the Norwegian continental shelf) and in permafrost regions (e.g. the Mallik gas hydrate field in the Mackenzie Delta of northwestern Canadian Arctic). Hydrocarbon clathrates are a problem for the petroleum industry, since their formation inside gas pipelines frequently leads to plug formation in the latter. Deep sea deposition of carbon dioxide clathrate to remove this greenhouse gas from the atmosphere has also been proposed.

Gas hydrates are created when water and gas combine to form a crystalline substance that looks like ice. This occurs when excess methane is present, and when temperature and pressure conditions are suitable. Gas hydrates are common in marine sediments along the margins of continents, where the methane originates from the decomposition of living things. Off the Oregon coast, the Juan de Fuca plate slides beneath the North American plate in a process called subduction. As subduction occurs, sediments are scraped off the Juan de Fuca plate and form ridges on the edge of the North American plate. This process leads to formation of gas hydrates.

Natural deposits

Worldwide distribution of confirmed or inferred offshore gas hydrate-bearing sediments.

USGS fact sheet on Gas Hydrates

Texas A&M University - College of Geosciences. article on:-
Resource Geosciences - Alternate Energy Sources from Deep Water.

Saturday, April 28, 2007

Tubing and Casing connection.

An oil field tubular connection is provided for joining metallic tubulars at a well site. At least one end of each tubular is provided with a frustoconical external sealing surface for metal-to-metal sealing engagement with a corresponding surface of an adjoining tubular. A plurality of antigalling grooves provided along the external sealing surface each project radially inward thereof and circumferentially encircle the threaded end of the tubular member and seal the groove from fluid communication with the interior of the tubular member. The antigalling grooves are particularly well suited for use with a low angular taper sealing surface of less than approximately 7 degree, and reduce galling between the metal sealing surfaces during makeup of the connection. Each tubular connection may also include an energizing groove spaced axially between the exterior sealing surface and the threads on the tubular member. The energizing groove receives excess thread lubricant, and has a uniform radial depth circumferentially about the tubular member for reducing the cross-sectional thickness of the tubular member, thereby allowing the exterior sealing surface to move radially outward in response to increased tubing pressure and allowing more flexibility for increased interference between the sealing surfaces during makeup of the connection.

Type of tubing connection:-
1) External upset.
2) Non-upset.
3) Flush Joint.

External Upset Tubing.

External Upset Tubing.
The external upset area near a tubing joint must achieve the structural integrity required to safely assemble the tubing string. In some cases, the upset area is used in handling the tubing string by providing a seat for the elevators. However, in many cases, special tubing elevators incorporating slips that engage on the external surface of the tubing wall are used to avoid excessive stresses in the tool-joint area.

Non-Upset Tubing.

Non-Upset Tubing
A non-upset tubing section, a tubular coupling, a connection for non-upset tubing sections, and a method for connecting the non-upset tubing section and the tubular coupling are disclosed. Methods for fabricating the non-upset tubing section and the tubular coupling are also disclosed. In one embodiment, the non-upset tubing section has an outer diameter of about 2 3/8 inches and, in another embodiment has an outer diameter of about 2 7/8 inches. The non-upset tubing section also has an externally tapered threaded surface having approximately eight rounded threads per linear inch. The tubular coupling has an outer diameter of about 2 7/8 inches, for use with at least one 2 3/8 inches OD tubing section, or about 3 1/2 inches, for use with at least one 2 7/8 inches OD tubing section. The coupling also has an internally tapered threaded surface having approximately eight rounded threads per linear inch and having a pitch diameter of about 2.258 inches for use with the 2 3/8 inches OD tubing section or about 2.729 inches for use with the 2 7/8 inches OD tubing section; Each pitch diameter is measured at a plane located about 1.250 inches from a plane located at a face of the coupling. To connect the non-upset tubing section with the tubular coupling, a thread compound is applied to either or both the threaded surface of the non-upset tubing section and the threaded surface of the tubular coupling. The non-upset tubing section is then inserted into one end of the coupling, and either the tubing section or the coupling is turned relative to its mating part until the non-upset tubing section and coupling reliably connect and seal.

Flush Joint Tubing

A type of tubing connection in which the internal or external surfaces are the same diameter throughout the tubing joint. Internal flush joints are most common, offering no restriction to fluid flow. Externally flush joints are typically used in more specialized applications, such as washover pipe for fishing operations, to allow adequate outer diameter (OD) clearance.

Flush Joint Tubing.

The TPS-MULTISEAL FLUSH JOINT Tubing and Casing connection is a non upset two step integral joint, suitable for use as liners and moderate depth casing. Characteristics:

-14° metal to metal internal pressure seal.
-30° metal to metal internal external pressure seal and torque shoulder.
-Completely flush OD and ID for maximum annular and running clearances.
-Pin and Box threads machined directly into pipe wall, no coupling required.
-Damaged threads can be simply cut off and remachined.
-Two step non tapered buttress type thread form.
-No thread intererence, so no tendency to thread galling.
-Stable two thread flank stabbing.
-Cannot be cross threaded.
-Fast make up.
-Integral connection halves the number of threaded connections (no mill connection).
-External pressure integrity in excess of pipe body.
-Repeatable sealing capability on multiple make and breaks.

Note: Some of the Flush Joint Tubing sometime is good for External sealing OD and internal sealing ID that the moving seal are can able to run thru without any interference on ID and OD but study with care is needed in the dimension.

-Disadvantage of using Flush joint tubing is it has lower tensile strength as compare to other type of tubing joint.
-Not for Hanging heavy hange weight, if really needed then the Well completion engineer have to be assure on the maximum hanging weight and the tensile strength of tubing joint.
-it normally come with thin wall.