Natural Gas Production and Processing Operations

There are two types of wells producing natural gas. Wet gas wells produce gas which contains dissolved liquids, and dry gas wells produce gas which cannot be easily liquefied

After natural gas is withdrawn from producing wells, it is sent to gas plants for processing. Gas processing requires a knowledge of how temperature and pressure interact and affect the properties of both fluids and gases. Almost all gas-processing plants handle gases that are mixtures of various hydrocarbon molecules. The purpose of gas processing is to separate these gases into components of similar composition by various processes such as absorption, fractionation and cycling, so they can be transported and used by consumers.

Absorption processes

Absorption involves three processing steps: recovery, removal and separation.

• Recovery.

Removes undesirable residue gases and some methane by absorption from the natural gas. Absorption takes place in a counterflow vessel, where the well gas enters the bottom of the vessel and flows upward through absorption oil, which is flowing downward. The absorption oil is “lean” as it enters the top of the vessel, and “rich” as it leaves the bottom as it has absorbed the desirable hydrocarbons from the gas. The gas leaving the top of the unit is called “residue gas.”

Absorption may also be accomplished by refrigeration. The residue gas is used to pre-cool the inlet gas, which then passes through a gas chiller unit at temperatures from 0 to –40 °C. Lean absorber oil is pumped through an oil chiller, before contacting the cool gas in the absorber unit. Most plants use propane as the refrigerant in the cooler units. Glycol is injected directly into the inlet gas stream to mix with any water in the gas in order to prevent freezing and formation of hydrates. The glycol-water mixture is separated from the hydrocarbon vapour and liquid in the glycol separator, and then reconcentrated by evaporating the water in a regenerator unit.

• Removal

The next step in the absorption process is removal, or demethanization. The remaining methane is removed from the rich oil in ethane recovery plants. This is usually a two-phase process, which first rejects at least one-half of the methane from the rich oil by reducing pressure and increasing temperature. The remaining rich oil usually contains enough ethane and propane to make reabsorption desirable. If not sold, the overhead gas is used as plant fuel or as a pre-saturator, or is recycled to the inlet gas in the main absorber.

• Separation.

The final step in the absorption process, distillation, uses vapours as a medium to strip the desirable hydrocarbons from the rich absorption oil. Wet stills use steam vapours as the stripping medium. In dry stills, hydrocarbon vapours, obtained from partial vaporization of the hot oil pumped through the still reboiler, are used as the stripping medium. The still controls the final boiling point and molecular weight of the lean oil, and the boiling point of the final hydrocarbon product mix.

Other Processes

• Fractionation.

Is the separation of the desirable hydrocarbon mixture from absorption plants, into specific, individual, relatively pure products. Fractionation is possible when the two liquids, called top product and bottom product, have different boiling points. The fractionation process has three parts: a tower to separate products, a reboiler to heat the input and a condenser to remove heat. The tower has an abundance of trays so that a lot of vapour and liquid contact occurs. The reboiler temperature determines the composition of the bottom product.

• Sulphur recovery.

Hydrogen sulphide must be removed from gas before it is shipped for sale. This is accomplished in sulphur recovery plants.

• Gas cycling.

Gas cycling is neither a means of pressure maintenance nor a secondary method of recovery, but is an enhanced recovery method used to increase production of natural gas liquids from “wet gas” reservoirs. After liquids are removed from the “wet gas” in cycling plants, the remaining “dry gas” is returned to the reservoir through injection wells. As the “dry gas” recirculates through the reservoir it absorbs more liquids. The production, processing and re circulation cycles are repeated until all of the recoverable liquids have been removed from the reservoir and only “dry gas” remains.

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Properties of Hydrocarbon Gases - Drilling Knowledge

Flaring Gas Testing

According to the US National Fire Protection Association, flammable (combustible) gases are those which burn in the concentrations of oxygen normally present in air. The burning of flammable gases is similar to that of flammable hydrocarbon liquid vapours, as a specific ignition temperature is needed to initiate the burning reaction and each will burn only within a certain defined range of gas-air mixtures. Flammable liquids have a flashpoint (the temperature (always below the boiling point) at which they emit sufficient vapours for combustion). There is no apparent flashpoint for flammable gases, as they are normally at temperatures above their boiling points, even when liquefied, and are therefore always at temperatures well in excess of their flashpoints.

The US National Fire Protection Association (1976) defines compressed and liquefied gases, as follows:

·     “Compressed gases are those which at all normal atmospheric temperatures inside their containers, exist solely in the gaseous state under pressure.”

·     “Liquefied gases are those which at normal atmospheric temperatures inside their containers, exist partly in the liquid state and partly in the gaseous state, and are under pressure as long as any liquid remains in the container.”

The major factor which determines the pressure inside the vessel is the temperature of the liquid stored. When exposed to the atmosphere, the liquefied gas very rapidly vaporizes, travelling along the ground or water surface unless dispersed into the air by wind or mechanical air movement. At normal atmospheric temperatures, about one-third of the liquid in the container will vaporize.

Flammable gases are further classified as fuel gas and industrial gas. Fuel gases, including natural gas and liquefied petroleum gases (propane and butane), are burned with air to produce heat in ovens, furnaces, water heaters and boilers. Flammable industrial gases, such as acetylene, are used in processing, welding, cutting and heat treating operations.

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Optimizing Artificial Lift Through Enhanced Control Systems

Canada is the world’s fifth largest oil producer. This is due in large part to the country’s vast reserves in and around Alberta, which contains the third-largest known oil reserves in the world.

Calgary-based ARC Resources Ltd. has called this oilrich region home for more than 20 years. The company has assets distributed across western Canada and operations that include E&P and development of conventional oil and natural gas.

Just across Alberta’s western border in northeast British Columbia, ARC Resources is one of the largest operators in the Montney region, which is considered one of the best tight gas plays in North America. And it was here that ARC Resources recently decided to begin optimizing the control systems it was using for its large multiwell natural gas production sites. The existing systems in place at these sites didn’t support artificial lift, which would soon be needed to maintain production levels. The systems also presented both expansion and safety challenges that the company wanted to address.

Operations at a crossroad

ARC Resources already had optimization programs at its smaller pads that contained only one to four wells. Control systems in place at these pads supported the use of artificial lift systems to help maintain or increase production as these wells depleted.

Larger pads of five or more wells, however, lacked control systems to support artificial lift systems. As some of these sites approached production milestones of 10 to 15 years, the company knew that it would need to make improvements in the near future.

“We were very successful with using assisted lift to keep production stable in the smaller fields,” said Charlie Kettner, programming specialist for ARC Resources. “We didn’t have the same optimization option in our bigger pads. So our production engineers wanted to find a control solution that would allow us to bring artificial lift to these fields as well.”

The existing controllers were not capable of handling the large amount of integrated operations required to run the entire well pad. As a result, the company had to use multiple controllers hardwired together along with remote terminal units (RTUs). This approach not only made the control infrastructure more complex and thus more prone to mistakes but also limited the amount of information available for control and monitoring.

The use of multiple hardwired controllers also presented safety challenges. ARC Resources relies on its control architecture to monitor toxic and explosive gases and to take actions such as turning on an exhaust fan or blocking wells as conditions dictate. But the controllers could lock up and freeze their outputs and give no indication that there was a fault. This forced the company to add “watch dog” timer hardware to monitor for such conditions.

A ‘canned package’

Kettner reached out to Rockwell Automation to begin discussions about optimization options that would support artificial lift systems at the large multiwell pads as well as simplify control and address safety concerns.

Their talks led them to the ConnectedProduction well manager system from Rockwell Automation, which includes an out-of-the-box Allen-Bradley ControlLogix programmable automation controller (PAC) and FactoryTalk View human-machine interface that requires no custom coding. The PAC gives ARC Resources single-platform control for large sites with up to 32 artificial lift wells and contextualized production information to help operators maintain optimal production levels and troubleshoot issues.

“It’s a canned package,” Kettner said. “You order it, install it and plug in your data to the points it’s looking for, and away you go.”

Kettner and his team decided to pilot the new technology at an eight-well production site named Sunrise near the town of Dawson Creek, British Columbia, before installing it at four other multiwell pad sites.

One of the benefits they first discovered during this trial run was the add-on instructions included in the ConnectedProduction, which helped them save about two days of programming during the installation process. Because the technology uses an open architecture, integration with other vendor hardware at the site was easy.

Enhanced visibility and safety

ConnectedProduction has eliminated the need for multiple controllers and RTUs that were previously in place at the Sunrise site. Now all well pad controls have been consolidated into a single control platform. In addition to simplifying the architecture, this will help lower hardware and software costs for the site.

The system also enables the use of artificial lift systems, including on/off timers and plunger lift systems, and provides visibility into those systems.

“Operators can track events in the Connected- Production solution to see what stage we’re in of the optimization cycle and make better decisions about what to do next,” Kettner said. “Operators can see, for example, that a timer well is not producing anymore and move to the next step of putting a plunger in the hole.”

The new system also is helping ARC Resources enhance safety by reducing the risk of faults going undetected at the Sunrise site.

“Now if something goes wrong with the processor, or if an I/O [input/output] rack comes undone, the ControlLogix platform can fault to a safe state where it shuts down all the processes,” Kettner said. “It takes all the power off the solenoids and essentially results in an emergency shutdown.”

Another benefit of the ConnectedProduction system is that it can support a flow-measurement card within the control panel. This has allowed Kettner to eliminate the use of a separate flow-measurement computer, which is saving his company tens of thousands of dollars at the site.

“We just plug the card into the rack, and it communicates on the backplane,” Kettner said. “It’s given us huge cost savings.”

Looking ahead, Kettner already has orders in to bring the ConnectedProduction system to at least four more large multiwell pads in the area.

“We’ve seen the value of the Rockwell Automation solution and want to bring it to our other sites where we need assisted lift,” he said. “On new pads we’ll implement this right from day one so it’s there and available when it’s needed. And we can just turn it on.”

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Big Shale Technology

Shale oil engineer Oscar Portillo spends his days drilling as many as five wells at once— without ever setting foot on a rig.

Part of a team working to cut the cost of drilling a new shale well by a third, Portillo works from a Royal Dutch Shell Plc office in suburban Houston, his eyes darting among 13 monitors flashing data on speed, temperature and other metrics as he helps control rigs more than 805 km (500 miles) away in the Permian Basin, the largest U.S. oil field.

For the last decade, smaller oil companies have led the way in shale technology, slashing costs by as much as half with breakthroughs such as horizontal drilling and hydraulic fracking that turned the United States into the world’s fastest-growing energy exporter.

Now, oil majors that were slow to seize on shale are seeking further efficiencies by adapting technologies for highly automated offshore operations to shale and pursuing advances in digitalization that have reshaped industries from auto manufacturing to retail.

If they are successful, the U.S. oil industry’s ability to bring more wells to production at lower cost could amp up future output and company profits. The firms could also frustrate the ongoing effort by OPEC to drain a global oil glut.

“We’re bringing science into the art of drilling wells,” Portillo said.

The technological push comes amid worries that U.S. shale gains are slowing as investors press for higher financial returns. Many investors want producers to restrain spending and focus on generating higher returns, not volume, prompting some to pull back on drilling.

Production at a majority of publicly traded shale producers rose just 1.3%over the first three quarters this year, according to Morgan Stanley. But many U.S. shale producers vowed during third-quarter earnings disclosures to deliver higher returns through technology, with many forecasting aggressive output hikes into 2018.

Chevron Corp. is using drones equipped with thermal imaging to detect leaks in oil tanks and pipelines across its shale fields, avoiding traditional ground inspections and lengthy shutdowns.

Ryan Lance, CEO of ConocoPhillips—the largest U.S. independent oil and gas producer—sees ample opportunity to boost both profits and output. ConocoPhillips also oversees remote drilling operations in a similar way to Shell.

“The people that don’t have shale in their portfolios don’t understand it, frankly,” Lance said in an interview. “They think it’s going to go away quickly because of the high decline rates, or that the resource is not nearly that substantial. They’re wrong on both counts.”

Shell, in an initiative called “iShale,” has marshaled technology from a dozen oilfield suppliers, including devices from subsea specialist TechnipFMC Plc that separate fracking sand from oil and well-control software from Emerson Electric Co., to bring more automation and data analysis to shale operations.

One idea borrowed from deepwater projects is using sensors to automatically adjust well flows and control separators that divvy natural gas, oil and water. Today, these subsea systems are expensive because they are built to operate at the extreme pressures and temperatures found miles under the ocean's surface.

Shell’s initiative aims to create cheaper versions for onshore production by incorporating low-cost sensors similar to those in Apple Inc.’s Watch, eliminating the need for workers to visit thousands of shale drilling rigs to read gauges and manually adjust valves. Shell envisions shale wells that predict when parts are near mechanical failure and schedule repairs automatically.

By next year, the producer wants to begin remote fracking of wells, putting workers in one place to oversee several projects. It also would add solar panels and more powerful batteries to well sites to reduce electricity and diesel costs.

Oil firms currently spend about $5.9 million to drill a new shale well, according to consultancy Rystad Energy. Shell expects to chop that cost to less than $4 million apiece by the end of the decade.

“There is still very little automation,” said Amir Gerges, head of Shell's Permian operations. “We haven’t scratched the surface.”

Technology, Geology

Much of the new technology is focused on where rather than how to drill.

“There is no amount of technology that can improve bad geology,” said Mark Papa, CEO of shale producer Centennial Resource Development Inc.

Anadarko Petroleum, Statoil and others are using DNA sequencing to pinpoint high potential areas, collecting DNA from microbes in oil to search for the same DNA in rock samples. ConocoPhillip’s MRI techniques also borrow from medical advances.

ConocoPhillips next year will start using magnetic resonance imaging (MRI) to analyze Permian rock samples and find the best drilling locations, a technique the company first developed for its Alaskan offshore operations.

EOG Resources Inc. last year began using a detailed analysis of the oil quality of its fields. The analysis, designed by Houston start-up Premier Oilfield Laboratories, helps to speed decisions on fracking locations and avoid less productive sites.

Premier has reduced the time needed to analyze seismic data to find oil reserves from days or weeks to seconds. Such efficiencies serve two purposes, said Nathan Ganser, Premier’s director of geochemical services.

“It’s not only removing costs thatare superfluous,” he said. “It’s boosting production.”

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Well’s Production prediction with Microseismic Technology

With efficiency being crucial when every dollar counts, operators in unconventional plays could add microseismic technology to fracture modeling methods to gain insight into permeability advances and better forecast production.

That’s according to Sudhendu Kashikar, vice president of completions evaluation for MicroSeismic Inc.

Understanding drainage volume and improved permeability of stimulated rock are essential to forecasting production, he said. Typically, several models are used to accomplish this, but the approach has its drawbacks.

A single frack model per stage ignores geological variations along the wellbore. Plus, a discrete fracture network (DFN) model is needed to determine how fracturing actually improves the permeability of stimulated rock, Kashikar said.

Microseismic techniques can simplify the workflow and help with production forecasting, Kashikar said during a webcast June 16.

“Technology and procedures were developed to discriminate the microseismic events and fractures described by these events, capturing propped versus unpropped fractures,” Kashikar said while describing Productive-stimulated rock volume (Productive-SRV) technology. “A rock volume capturing the proppant-filled refractures showed much better correlation to the cumulative production than the total stimulated rock volume.”

Productive-SRV technology estimates how much stimulated fracture remains open through proppant placement by using estimated target zone productivity, a DFN, propped fracture estimate and the Fat Fracture drainage estimate, according to MicroSeismic’s website.

Focus is usually on the location of the proppant, but focus should also be on the amount of improved permeability achieved within the SRV or the Productive-SRV, he said.

Understanding and measuring such improvements will lead to the next step in reservoir stimulation and production forecasting, he said.

Using microseismic data has proven beneficial in establishing a deterministic DFN, which shows fractures detected through seismic.

“For every microseismic event we describe a fracture plane. The size is guided by the magnitude, and the orientation comes from the focal mechanism,” he said. “This is much easier to do with surface microseismic.”

The model is calibrated to actual fluid volumes pumped for a well. A mass balance approach is used to fill the fractures with proppant starting from the wellbore moving outward until the proppant is consumed for that stage, Kashikar explained. Once the fracture network and the propped network have been established, a geocellular grid can be superimposed to obtain the SRV and productive SRV to capture the proppant-filled rock volume, he said.

“One advantage of this workflow is the ability to capture fracture intensity—the number of fractures, the orientation of these fractures—to quantify the permeability enhancement achieved,” Kashikar added.

Key steps for the production forecasting workflow are describing three reservoir volumes—the productive SRV (the propped fractures), total SRV (includes propped and unpropped fractures) and the permeability scalar for individual cells within each region to determine how permeability improved for neighboring cells.

This workflow, he said, captures not only the size and shape of the drainage volume but also permeability within the drainage volume.

The process is a big step forward, he said, in understanding and determining the effectiveness of hydraulic fracturing.

“Rather than relying on a single representative fracture model, we can fully and accurately capture the variable fracture geometry and fracture intensity for the entire length of the wellbore, providing a much better production forecast,” Kashikar said. “We can now use the productive stimulated rock volume and the stimulated rock volume with permeability scalars to directly and explicitly describe the reservoir volume in the reservoir simulator.”

Source: www.epmag.com

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How to make LNG - Liquefied Natural Gas

In liquefaction plants, NATURAL GAS (mainly METAN ) is brought to the state of saturated liquid at a temperature of about-161 ° C and ambient pressure, with a volume reduction of more than 600 times; In international trade, LNG ( LPG NATURAL LIQUID) is loaded and transported by sea into the double hull tanks of special vessels, called methane, with a loading capacity of up to 150,000 m3.

The regasification process takes place in special terminals and consists in generating liquid pumping from the vessel tank to the terminal tank, in a subsequent COMPRESSION and heating up to the inlet temperature in the pipeline (Figure - Scheme of the regasification and layout process of a type plant ).

LNG drainage from the ship to the terminal takes place through the submersible pumps in the ship's tanks; the liquid is then sent from the STOCCAGGIO storage tank to the vaporizers by means of delivery pumps (multistage centrifuges), which have the task of ensuring the pressure required by the regasification operations.

The operating pressure of the terminal varies significantly according to the intended use for NATURAL GAS and, in the case of a DISTRIBUTION network , they are normally higher than the critical one (46 BAR for the CH4).

In vaporizers, the LNG passes over heated to a temperature dependent on the heat source.

The two most popular types are: open ranks, using sea water, and submerged flames, which use as a source of heat water heated by an internal burner.

If the required heat is supplied by seawater, this, after being pumped into vaporizers, is discharged into the sea at a temperature below 7 ° C compared to the inlet.

The NATURAL GAS is sucked and pressurized by compressors to then be injected into the network or sent to the user; one part is often used for self-consumption of the plant: in fact, the terminal is normally equipped with an electric power generation system consisting of Diesel or turbocharged engines.

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Nigeria, The First Crude Oil producer in The African Continent

Nigeria, or rather the region of the Niger Delta, is notorious for the continued tensions between local multinationals and guerrillas (and the consequent repercussions on the country's oil activity and crude oil prices) is one of the richest areas of hydrocarbons.

The quantity and quality of these resources have attracted the interests of the major Western companies that have been operating in the oil and, most recently, in the gas sector for decades.

The first crude oil producer in the African continent, member of OPEC, the country oscillates between the sixth and the eighth position as a world exporter and is the fifth supplier of the United States, while the recent results obtained under the NATURAL GAS liquid prelude to a protagonist future also on this market.

Nonetheless, over 60% of Nigeria's 150 million people live in an endemic poverty stash, with less than a dollar a day.

A situation of marginalization and exploitation to which the institutions could not answer - complicit also the corruption of a political class more attentive to their own personal interests than to the needs of the population - and who is degenerated into rebellion and violence perpetrated against the foreign oil installations and Western technicians, by local militias fighting in the name of the emancipation of their land and direct control over their resources.

In a descriptive and accessible way to everyone, the book by Agata Gugliotta, "Nigeria, whose resources? Oil and gas in the Niger Delta "reconstructs the economic and political life of Nigeria seen through black gold, the resource that still hinders the way of being a state enslaved to the needs of private capital; contextualizes the motives and developments of a revolt that, overwhelmingly overwhelmingly over time, has just recently swung to the backdrop of the media; analyzes what might prove to be a ransom for the country, or, conversely, an accelerator of the crisis: the exploitation of gas resources.

Burned in torch for decades, gas - considering the magnitude of RESERVES on site and its growing role in the international energy landscape - could offer the country a new stage of development and create opportunities to get out of the economic crisis and the climate of violence which attracts him.

But regardless of the time and the uncertainties related to the development of the gas sector, the economic and social degradation, the ' pollution of air, water and land every day that the Nigerian population is forced to suffer, they require urgent attention.

On the other hand, as the pages of this page show - written in a delicate but acute civil passion - the conflict that has bloomed Nigeria for a long time is likely to get stuck further, leading to a collapse of an economy already on the brink and making it increasingly difficult to see the presence and the " activities of Western multinationals.

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Types of Oil Vessels Shipping

One factor you need to consider is whether you are going to get a petroleum commodity exposure through industry, oil transportation is the same vessels. Before investing in a warehouse tanker, carefully examine the fleet of working ships.

To help you in this exam, here are some of the types of ships used in the crude oil-transport global industry:

• Ultra Large Crude Carrier (ULCC): This type of ship, known in the industry as the ULCC, is the largest ship in the market. It is used for long-haul travel. It offers economies of scale as it can carry large amounts of oil over long distances.
• Very Large Crude Carrier (VLCC): The VLCC is the vessel of choice for long distance sea trips. It is ideal for intercontinental shipping; its areas of activity are the Persian Gulf for East Asia and West Africa to the United States, among other routes.
• Suezmax: This vessel is called so because its design and dimensions allow transit through the Suez Canal in Egypt. Suezmax is among the vessels used to transport oil from the Persian Gulf to Europe, as well as to other destinations. It is ideal for mid-range trips.
• Aframax: The Aframax, whose first four letters are the acronym of Average Freight Rate, is considered the "battle horse" of the fleet of tankers. Because of its smaller size, it is ideal for short-haul travel and has the ability to transport crude oil and products to most ports around the world.
• Panamax: Like Suezmax, Panamax takes its name from its ability to transit through a channel - in this case, the Panama Canal. This vessel is sometimes used for short-haul trips between the Caribbean ports, Europe, and the United States.

In addition to their captivating names, these vessels are identified as crude oil and products that can carry them to sea. The unit used to capture this capacity is known as the Dead Weight Ton, or DWT. DWT measures the weight of the ship, including all loads it carries. Most ships are built in such a way that 1 DWT is equivalent to 6.7 barrels of oil.

Vessel Type Dead tons of weight Equivalent to Petroleum (barrels)

ULCC            320,000 and up                    2+ million

VLCC            200000-320000                    2 millions

Suezmax             120000-200000                   1 million

Aframax              80,000-120,000                   600,000

Panamax              50,000-80,000                    300,000

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Drilling Well Pacing

The pacing process and can be used to improve the flow of natural gas or crude oil into a well hole. This can be accomplished through a variety of intervention techniques, many of which are designed to increase permeability outside the hole. The two ways of increasing permeability are to clean the formation or increase drilling and fracture in the tank. Another technique that can be effectively used in pacing is good gas lifting, which can be useful to start a well or extract heavy compounds that are actually killed. All of these various stimulation techniques and can improve the output of a petroleum or gas reservoir, increasing the incoming hydrocarbon stream and hole.

When the oil or gas is in an easily removable form, it is usually found in a reservoir. These tanks are porous or fractured rock formations that the oil or gas is contained inside. To extract hydrocarbons, a well hole can be drilled in the formation. The oil or gas will then tend to penetrate through porous or fractured rock, into the hole, and up to the surface. A common form of intervention is the process of stimulation, which is designed to speed up the rate at which hydrocarbons move through the formation.

One of the common methods of stimulation is to increase the permeability of the oil or gas tank. The permeability of the formation is often reduced due to the drilling process, and chemicals can enter and block porous rock. Drilling can also force rock fragments into cracks and cracks, further blocking the reservoir. To clean the formation, the chemicals are often pumped along the hole to melt the blocks. Formic acid is often used in a process known as acidification, which can dissolve blocks and allow hydrocarbons to flow.

Another way that the permeability of a formation can be increased is to create additional crevices or fractures in the rock. Hollow loads are a type of shaft stimulation that can increase the number of fractures near the well hole. Another method is hydraulic fracturing, which can result in pumping high pressure fluids along the well hole. Other explosive materials can also be used to release high pressure propellants in the formation, creating additional cracks and fractures inside the tank.

Gas lifting is a pacing technique that can be used to get the flow started or to repair a well that has been killed. This technique generally involves the circulation of nitrogen or other substances with spiral tubes. Sometimes, this is only done to get the flow started, after which the nitrogen circulation has ceased. In other cases, the same technique can be used to lift heavy substances, such as chemical scale reducers or water, which have been established in the hole and blocked the flow of hydrocarbons.

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What is Lifting Gas ?

Gas Elevator is a method to increase the natural reach of an oil well by reducing the weight of liquid in the column by means of high pressure gas injection. The weight of oil in the column well, with the resistance caused by the viscous crude oil flow through the system well, the natural pressure of the reservoir must be exceeded to provide flow. Gas injection near the bottom of the column and reduces the density of the oil, and the total weight of liquid within the column well. Gas lift plants are generally more compact and require less energy than other methods of increasing flow rates, and are a popular solution for offshore drilling projects.

Most oil reserves are under adequate natural pressure to provide an economic rate of flow at the time of the first exploited. As oil is removed from the tank, however, the pressure decreases and the flow rate slows or stops completely. Since this usually occurs before the bulk of the oil has been removed from the tank, the rest of the oil can be utilized by reducing the downward pressure of the column and reservoir. This can be done by pumping the oil directly through the column, replacing the missing oil in the tank with water or other liquids, or by reducing the weight of the liquid in the column.

The gas is injected into the column and either through the well of the well or directly through the production tube. If the gas is injected through the well coating, the gas inlet valve is usually placed in a spindle, a kind of niche built on the side of the production tube. This allows the oil to flow through the pipe without being obstructed by the gas injection equipment, and is generally favored in low volume wells. In larger wells, the gas lifting system can be lowered into the production tube directly without significantly affecting the oil flow.

In the case of most land-based wells, other streamlining methods are simpler and cheaper than gas lifting. It is mainly used on offshore drilling rigs, where space is a premium and the compact nature of the injection mechanisms is an advantage. It is also used in petroleum fields that produce a high volume of natural gas. The gas can be passed through a washing plant to purify and dry the gas on site, where it can be injected immediately into oil wells with marginal production. Once the gas is injected into a well, the majority is recovered to the surface and can be compressed and re-injected without a large amount of waste.

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Fixed Platform for Oil-Gas drilling and Production

A fixed platform is a permanent structure attached to the bottom of the ocean, often for the purpose of offshore oil extraction. Most of the work space of this platform is lifted over the surface of the sea from rigid steel or concrete supports. This rules a fixed platform with mobile platforms floating on the surface of the sea and anchored to the bottom of the ocean by more or less flexible moorings. Fixed platforms are typically deployed in water less than 1,700 feet (520 meters) in depth, with deeper drilling activities requiring more complex mobile platforms.

The first productive offshore oil wells were drilled in Ohio Grand Lake St. Marys State Park in 1891, using fixed platforms set on wooden piles at the bottom of the lake. In 1947, the first fixed platform drilling rig located beyond the view of the earth was built in the Gulf of Mexico. Fixed platforms were the most common method of offshore drilling for most of the 20th century, although the first mobile drilling rigs were operating since the early 1930s. Due to their high stability, depth limitation, and high, modern cost Fixed platform drilling rigs are limited to long-run drilling operations in shallow waters.

Fixed platforms are connected directly to the bottom of the ocean by a structural support known as a jacket. The first jackets consisted of concrete foundation poles, while modern deep water jackets are the tough towers of steel tubular supports. The base of a coating can be several times larger than the top, and are often driven deep into the ocean floor mud for support. The jackets are either partially or entirely built to the ground and shipped to the deck's position on bargain tugboats. Once there, they dropped to the bottom of the ocean with the help of ROV, and pushed them into position using bats mounted on barges.

The bridges that form the work space of a platform are generally built on sheltered yards or bays. While the first barges were towed on barges, many modern bridges are built to float during transit. They got to the top of the waiting jacket using hydraulic jacks or barges, and are usually quite high above the floating line to avoid all but the biggest waves. Bridges can be up to 200 feet (60 meters) in diameter, and consist of several levels of work and living space.

If a fixed platform is near the shore, you can pump oil directly from the onshore drilling site of storage facilities through gas pipelines provided along the ocean floor. In the case of drilling operations far from the ground, the platform must include large reservoirs containing the oil as long as it can be transferred to a tanker. Storage tanks are often located below the floating line, where they serve as a ballast to help the platform withstand the power of waves and currents.

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Maritime transport on oil tankers

The shipping of oil on board tankers (tankers and super tankers carrying up to 400,000 tons of crude oil), represents more than half of world maritime trade. One can imagine the consequences of oil shortage on commercial! (On others for that matter ...).

Initially the oil was transported aboard wooden casks (barrels). The barrel has remained the unit of exchange used. It is 159 L. Now tankers are designed as huge reservoirs, sometimes divided into several compartments to store oil of different characteristics (including density). So we can better manage the weight distribution on the ship.

Over the past 30 years, many maritime disasters involving super-tankers have been held. They have caused ecological and economic disasters along the coast affected by oil spills. Most of the cleanup costs and compensation were supported by local e local governments. The Coastal Cleanup is in turn often provided by volunteers.

Since then, new oil transport ships are equipped with double hulls, which are supposed to reduce disaster risks. But they do not prevent the practice of degassing, responsible for oil spill at sea ... The single-hulled tankers still represent the vast majority of the park. 

The gigantic size of the super-tankers creates monstrous consumption of fuel, but which are reasonable compared to their carrying capacity. Currently, more than 600 tankers with a tonnage greater than 200,000 tonnes in circulation.

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Cracking and reforming

Cracking is to break the long hydrocarbon molecules into smaller molecules. This can be done by thermal process under high pressure, or catalytic (under high temperatures and in the presence of a compound that facilitates the chemical reaction). When hydrogen is involved, it is called hydrocracking, is when water is called steam cracking. 

The reforming to convert naphtha to produce gasoline or premium. 

There are other processes refining as isomerization, alkylation, etc. ... We can thus influence the characteristics of the products obtained (octane, color, odor, volatility ...).

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Distillation

Crude oil is first heated to 370 ° C. It then partially vaporizes and is carried out in a fractionating column (a kind of distillation tower). 

At the top of the column is recovered refinery gas used as fuel on site. It also recovers other petroleum gas such as butane and propane, gasoline and naphtha. The latter is the base compound of the petrochemical industry. Then recovered kerosene (used iFn aviation, the jet engines), diesel and heating oil. Further down the column is recovered residues, which are re-distilled under vacuum to provide heavy fuel oil, lubricants and bitumen. 

In order to obtain specific grades of gasoline (high octane) and reduce the content sulfur diesel fuels, we must also deal with products of distillation.

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Drilling for oil

After the drilling of one exploration well, designed to confirm the presence of oil and other wells are drilled to delineate the deposit. Most wells are drilled using a drill bit, a cutting tool on the end of a set of drill pipe supported by a metal tower called derrick. The drill bit is rotated. The drilling speed varies greatly depending on the nature of the rocks traversed. Of the "drilling mud" (a mixture of clay with water and chemicals) is continuously injected inside the stems. It goes back into the space between the rods and the walls of the well. The mud serves to cool the drill bit and remove the cuttings. Back on the surface, the slurry is filtered and reinjected into the well. Analysis of the debris can qualify the rocks traversed. 

Advances in drilling techniques now allow the completion of drilling small diameter boreholes deviated (obliques), horizontal multidrains, etc ... This progress has allowed the exploitation of deposits that were previously unprofitable, for technical reasons and / or economic. 

For offshore deposits (offshore), is generally used for pumping platform independent. Special ships can be used to exploit deposits of lower capacity.

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