The industrial gas industry supports and enables energy production from many different sources in a surprising numbers of ways. Tony Wheatley takes us through this range of applications.

Gases supplied by offshore services
Driven by high crude oil prices, the exploration of potential new oil and gas fields is either underway or planned in many parts of the world, including the West African Coast, Indian Ocean, South China Sea and the Arctic Ocean.

These operations depend heavily on supplies of a range of gases that are used aboard a variety of offshore installations and vessels, where conventional delivery services are impossible.

Requirements include Argon/CO2 welding mixtures for equipment and plant maintenance, helium/oxygen blends for breathing gas used by undersea divers, nitrogen for purging and leak detection, speciality and calibration gases plus oxygen and other medical gases.

There are many standards and regulations unique to the Oil Industry and gas suppliers have to ensure that these requirements are met which includes full QC certification, correct and relevant documentation, product traceability and appropriate packaging.

High pressure gas cylinders for offshore use are typically fitted into welded steel frames that can be easily loaded onto supply ships and hold them securely together during transport and use. This convention also simplifies the task of tracking and managing the movement of gas cylinders that would otherwise be a logistical nightmare.

Carbon dioxide and other gases in enhanced oil recovery (EOR)
The true volume of oil available from any given oilfield is always less than the estimate of original oil in place (OOIP) because of difficulties in getting the oil to the surface influenced by the viscosity of the oil deposit, reservoir temperature, pressure and crude oil composition.

Three phases are now recognised in the process of crude oil production:
Primary phase production usually extracts no more than 10 % of a reservoir’s oil before the natural pressure is reduced by removal of oil and gas, and no longer drives oil to the wellbore fast enough to maintain acceptable a production rate – even with artificial extraction techniques such as pumps.

Secondary phase extraction requires the injection of water for two reasons; to maintain the pressure by replacing the oil that has been taken out (referred to as voidage replacement) and to sweep or displace the oil from the reservoir, and push it to the oil production well. Water is discharged into the aquifer through several surrounding injection wells thus creating a bottom water drive on the oil zone and pushing the oil upwards. This phase can bring the percentage of recovery up to around 40% of the estimated OOIP.

Tertiary or Enhanced phase techniques have been developed over the past 40 years to address the problem that many ‘depleted’ oilfields, especially in the US, have up to 60% of their oil unrecovered. Three major categories of EOR have been commercially proven including:
Gas Injection is the most popular method and also of greatest interest to gasworld readers.

CO2 gas injection was invented in 1972 and has been applied throughout North America using CO2 mostly from naturally occurring sources, until recently. New industrial sources that obtain CO2 from natural gas processing, ethanol, fertiliser or hydrogen plants have been used in areas without a natural source.

It is likely that the implementation Carbon Capture and Sequestration technologies will be linked to EOR projects that require large quantities for CO2 gas injection.

CO2 is soluble in crude oil deposits and has the effect of reducing its viscosity, thereby increasing the rate at which oil flows to the wellbore and enabling the injection of immiscible fluids at low pressure. The temperature, pressure and composition of the oil in the reservoir also affect the phase behaviour of CO2 and crude oil mixtures.

Completely miscible displacement requires high pressure injection and up to 60% of the CO2 returns with the oil produced by this mechanism, to be either re-injected or trapped in the reservoir.

Hydrogen and oxygen in oil (tar) sands recovery
Oil sands (also called tar sands) contain around 10% Bitumen in a mixture of silt, clay, and water that is 75% inorganic. Bitumen is a heavy crude that does not flow naturally because of its high viscosity and sulphur content. The US Geological Survey claims that over 80% of the world’s technically recoverable natural bitumen lies in North America and Canadian oil sands represent approximately 14% of global oil reserves.

Canada has pioneered the recovery of oil from these deposits, producing about 46% of its total oil from this resource, predicted to reach 2.8 million barrels per day by 2015. Oil tar sand is sold in 2 forms: as raw bitumen blended with a diluent for transport or as synthetic crude oil after being upgraded.

Mining the oil sand is preferred where the overlying rock does not exceed the thickness of the oil sand deposit and is less than 75m thick. After crushing up to 90% of the bitumen is extracted from the slurry to be either sold as raw bitumen or upgraded and sold as Synthetic Crude Oil.

There are up to four different in-situ extraction processes where mining is impractical.
These are:
The Cold Production method is used for about a third of Canada’s oil sand production where oil sands are light enough to flow to the well bore without heat.

The most widely used in situ process is the Cyclic Steam Stimulator (CSS) which injects steam to heat the oil sands via a vertical well and the liquefied bitumen is then pumped to the surface through the same well but achieves only 25-30% recovery.

Steam Assisted Gravity Drainage (SAGD), operating at a lower steam to oil ratio, has increased recovery to as much as 70% of the bitumen in place and will replace the CSS in most new in-situ projects.

An emerging technology named the Vapour Extraction Process (VAPEX) replaces steam with ethane, butane or propane injected into the reservoir to mobilise the bitumen towards the production well. By eliminating steam generators, the requirment for water and natural gas are also eliminated and the process operates at half the cost of SAGD, requiring only 25% of the capital investment.

Before extracted bitumen can be processed further by conventional refineries it must first be upgraded into light synthetic crude oil, involving the use of gases.
The Research Institute of Petroleum Industry (RIPI) claims that its hydro-conversion process has certain advantages over the traditional hydro-cracking process. The hydrogenation and operating conditions allow higher conversion without coking and excess polymerisation and can eliminate all heavy metals and almost 30% of sulphur components.

Feedstock is hydrogenated by hydrogen gas in the presence of a catalytic complex, a process that can reduce gravity of heavy crude from 7-20 API to 30-35 API, converting it into light synthetic crude of increased value.

Supporting the role of gases in this innovative process, an abstract of a US Patent Issued on 16th August 1983 explains, “An integrated process for the production of fuels from tar sands in which bitumen is recovered from the tar sand by a hot-water separation step, recovered bitumen is converted in a hydroconversion step to gaseous and liquid fuels. Carbonaceous residue from the bitumen conversion step is gasified with oxygen, to produce synthesis gas…”

Nitrogen in natural gas distribution
Natural gas (primarily methane CH4) is often converted to liquid form by cooling it to approximately -163°C (−260°F) as liquefied natural gas (LNG) takes up merely 1/600th the volume that it would as gas at atmospheric pressure.

The reduction in volume makes it much more cost-efficient to export natural gas over long distances by specially designed cryogenic sea vessels (LNG carriers) where pipelines do not exist. Imported LNG is typically received into an offshore re-gasification terminal, where it is reheated and turned into gas.

LNG produced around the world varies in composition depending on the nature of reservoir fluids, whether or not they are associated with an oil production, and how much LPG is extracted during liquefaction. And to further complicate matters, for historical reasons individual nations have developed different gas specifications.

Economic reasons drive the exporter to limit the presence of nitrogen in the LNG: it is hard to liquefy, and of no value unless it enables the sale of a cargo to a market which has a low limit on HHV or WI.

In order to ensure that the re-gasified LNG can be burnt safely and efficiently, it must be interchangeable with the gas the customer is used to. This is measured by the Wobbe Index (WI) which is a measure of the degree to which the combustion properties of one gas resemble those of another.

Nitrogen ballasting has a particularly strong effect on Wobbe Index. The addition of nitrogen to LNG reduces the HHV of re-gasified LNG because nitrogen is an inert gas. Meanwhile, the addition of nitrogen increases the Relative Density of the mixture, the Relative Density of nitrogen (0.969) being significantly higher than that of methane (0.556).

Nitrogen injection is a safe and well proven technique for quality adjustment in the case of
LNG being too rich compared to the local network specifications.

Gases in the coal-to-oil process
Coal-to-oil technology dates back to the 1920’s, when two German chemists, Franz Fischer and Hans Tropsch, developed a process to convert coal into a gas and then use it to make synthetic fuels. International oil companies also experimented with the process but put it aside because oil was cheaper.

The lone exception was South Africa, where Sasol Ltd. built several coal-to-liquids plants, and became the world’s leading purveyor of coal-to-liquids technology. In the Sasol process coal is gasified in the presence of oxygen and steam to yield a synthesis gas containing methane, carbon monoxide, hydrogen, carbon dioxide, ammonia, hydrogen sulphide, steam and numerous other compounds.

Coal-to-oil projects also pose serious environmental questions. When the South African facility superheats coal and turns it into a gas, one of the main waste products is carbon dioxide, thought to be a significant cause of global warming. Coal-to-oil plants have been described as carbon-dioxide factories that produce energy on the side.

Oxygen in coal gasification
State-owned Chinese energy conglomerate the Shenhua Group recently announced eight coal-To-Liquids (CTL) projects in the pipeline and a target of 30 million tons per year by 2020. They confirmed negotiations with the South African company Sasol Synfuels to enter a technology agreement and the first three of the eight projects will have a total capacity of 4 million tpy, and are due to be completed by 2010.

The eight plants will be built in Shaanxi, and the autonomous regions of Inner Mongolia, Xinjiang Uygur and Ningxia Hui.

In January 2007, Praxair China announced an agreement to build, own and operate a 3000 tpd oxygen plant (the largest single-train air separation unit in Asia to date) to be integrated with a low-cost coal-gasification process for Jiangsu SOPO in East China.

Gases in nuclear power generation
Nuclear power has re-emerged in the headlines of late, as a possible alternative energy source once again. The nuclear fuel is often in the form of a ceramic contained within spherical pebbles made of pyrolytic graphite, which acts as the primary neutron moderator.

Each sphere is around the size of a tennis ball and effectively a complete ‘mini-reactor’ in itself, containing all of the parts that would normally be separate components of a conventional reactor. Simply piling enough of the fuel spheres together will eventually reach criticality.

The fuel zone of a single sphere can contain up to 15 000 ‘particles’, with each particle coated with a special barrier coating which ensures that radioactivity is kept locked inside the particle. The reactor is loaded with over 440,000 spheres – three quarters of which are fuel spheres and one quarter graphite spheres – at any one time. The graphite spheres are used as a moderator. They absorb and reduce the energy of the neutrons so that these can reach the right energy level needed to sustain the chain reaction.

Fuel spheres are continually being added to the core from the top and removed from the bottom. The removed spheres are measured to see if all the uranium has been used and if this is the case, the sphere is sent to the spent fuel storage system. If not, it is reloaded in the core – an average fuel sphere will pass through the core about 10 times before being discharged.

The pebbles are held in the reactor vessel where inert helium gas plays a significant role, circulating through the spaces between fuel pebbles to carry heat away from the reactor. The heated gas is run directly through a turbine.

Nitrogen in EOR applications
Natural gas and nitrogen are also used where available for gas injection EOR applications.

The largest ever industrial gas agreement was signed in 1997 by Pemex, the Mexican government-owned oil company, for a BOC-led consortium to build a 40,000 tpd nitrogen plant for EOR at Cantarell.

In 2004 BOC announced a new 20 year agreement under which a fifth production module would be built raising the total output to 50,00 tpd of nitrogen from 2007.

Praxair is currently starting up its largest EOR project to date – two plants that will deliver 6,800 tpd of nitrogen in Samaria, southern Mexico are expected to recover an additional 470 million barrels of light crude oil and 540 million cubic feet of natural gas through 2018.

Air injection is a lower cost option for gas injection, requiring less capital investment. The Japan Oil, Gas and Metals National Corporation (JOGMEC) have plans to conduct field tests with the objective of acquiring air injection technology.

The pebble-bed reactor (PBR)
Further developments in nuclear technology could be on the horizon in China following the recent launch of two new pebble-bed technology projects last year.

Of the two progressive projects, one is a prototype modulator plant, HTR-PM, intended to demonstrate the commercial potential of the HTR-10 pebble-bed technology. The other is a helium gas-turbine generator system, coupled with the original HTR-10 reactor.

China is also preparing to build a 190 mw demonstration reactor power plant at Rongcheng in Eastern China and, if successful, a total of 19 pebble-bed reactors generating 3600 mw will be constructed at that site.

The pebble-bed reactor (PBR) technology is an advanced and significantly safer form of nuclear power as described, achieving higher thermal efficiencies than traditional nuclear power plants and using inert or semi-inert gas such as helium, nitrogen or carbon dioxide as the coolant

Such technology was first developed in Germany but is currently under ongoing research and development in the US, China and South Africa.
Indeed in South Africa, the development of hi-tech nuclear power continues to forge ahead and a new plant could be the first in a new generation of helium gas-cooled reactors.

An R17bn capital investment project will provide one of the solutions to South Africa’s power problems by 2013 and although not the only technology under development, the project is to become the first commercial-scale high-temperature reactor in the world.

A high-temperature helium gas-cooled reactor is set to be the first of a new generation and the project entails building a demonstration reactor at Koeberg outside Cape Town, and a pilot fuel plant at Pelindaba near Pretoria.