Elaine Maslin takes a look and describes how EOR is fast becoming a priority in the Middle East, not least the UAE.
|The TriGen gas generator system, side view|
Changes are coming to the United Arab Emirates (UAE), which are likely to hail changes in the companies making up the operating community, and how they operate. According to the Energy Information Agency (EIA), the UAE holds the seventh-largest proved reserves of natural gas in the world, at just over 215Tcf. Despite these numbers, the UAE became a net importer of natural gas in 2008, due to heavy use of natural gas for reinjection, for enhanced oil recovery (EOR), and growing domestic demand for electricity, largely from gas-fired facilities.
With the likelihood of any further major oil discoveries low, according to the EIA, EOR will play an increasing role in the region, if production is to be maintained or increased.
The issues are not lost on Abu Dhabi National Oil Company (ADNOC), which has plans to increased daily production capacity to 3.5MM bbl/d, from 2.8MM bbl/d.
ADNOC is also looking to reduce CO2 emissions. The firm recently signed a joint venture (51:49) agreement with Masdar to set up the Middle East’s first company focused on exploring and developing commercial-scale projects for carbon capture, use and storage.
The JV plans to extract CO2 at Emirates Steel, the UAE’s largest steelmaking facility, compress it, and then transport it to ADNOC-operated oilfields for EOR, and storage. The project will sequester up to 800,000-ton of CO2 annually, says ADNOC.
The agreement has already seen an AED450 million engineering, procurement and construction contract awarded to Dodsal Group to build a carbon dioxide (CO2) compression facility in Abu Dhabi, and a 50km pipeline, with project completion due in 2016.
In addition, ADNOC is currently selecting new partners for its legacy onshore concession, due to expire this month [January], and an offshore concession, scheduled to expire in 2018.
It is understood new concessions being offered offshore Abu Dhabi by ADNOC will contain requirement for EOR initiatives in order to take recovery rates to more than 60%, says Moss Daemi, executive VP Middle East and Africa at DNV GL.
Oil firms have previously offered their expertise for CO2 EOR in the region, including BP, but with limited uptake, due to not being deemed commercially attractive enough, in a region “floating on oil”, and technically challenging.
It has been tried, however. In 2009, ADNOC’s onshore operating company, started injecting CO2 at the onshore North-East Bab field, Rumaitha. In 2009, Saudi Arabia’s Aramco announced plans to trial CO2 injection on mature fields including Ghawar.
With concessions becoming available, operators are again offering their EOR expertise, including Maersk.
Bob Alford, senior business development manager, Maersk Oil Middle East, says Maersk has developed skills in tight, chalk, low permeability carbonate reservoirs, common offshore Denmark, and in the Middle East.
Maersk has been operating the Al Shaheen field offshore Qatar since 1992. It had been deemed uneconomic to produce, but it is now the biggest field in Qatar, producing 300,000 bbl/d.
|How TriGen could fit into a power, water and CO2 for EOR system|
“The rock properties are very similar here in Abu Dhabi, so we are excited about the opening of the market,” says Alford.
Maersk now has new technology up its sleeve, which it wsays will help increase EOR on this type of field, and residual oil zones, without using imported natural gas, as well as producing power, for the local grid, and water, without the need for desalination—another issue facing the Middle East.
Maersk has developed, with the help of ex-NASA scientists at California-based Clean Energy Systems, Inc., TriGen, an oxycombustion process, derived from the space industry.
Similar technology was used for the main engine of the space shuttle, which has a power output similar to that needed to power all of California or the entire UK national grid, says Alford. An air separation unit is used to separate nitrogen and oxygen from air, through a cryogenic distillation process. The oxygen then goes into a high pressure (20-80 bar), high temperature, OxyFuel gas combustor, with turbo expanders, and re-heaters, based on rocket-engine combustion principles, to generate electricity.
“We are mixing the oxygen, gas and water together and burning it across a very short distance,” says Alford. “As we mix it together we are combusting it at more than 2000°C. Water is used to partly cool the gas before it hits the turbine blades and stop them melting, as their materials are not ready for this level heat yet. As we can get turbines able to operate with the higher temperatures we would be able to further increase the efficiency.”
A key element of the Oxycombustor is “platelet” technology, which is used for the fabrication of the combustor, to control the reaction during the Oxy- Combustion process, to ensure the oxygen and fuel mix to form a homogenous flame front, avoiding hot spots or producing un-combusted product.
The technology, which involves, thru and partial-depth patterns chemically machined in thin sheets of metal, producing “platelets,” was developed by Maersk’s partner Clean Energy Systems.
The platelets are “stacked”, and joined by solid state diffusion bonding to form a structure containing internal passages, with precise flow control manifolding and metering features, and filters.
TriGen’s turbines are based on existing technology machines, such as the Westinghouse W-251 (Siemen’s SGT- 900) are able to work with CO2 or steam as a drive gas, because they can produce drive gas at any combination of pressure and temperature.
TriGen can also take in contaminated fuel gas streams, especially with CO2. “It can be used for non-associated gas that you do not otherwise know what to do with,” says Alford. After combustion, a simple process is then used to separate the water and CO2 from the gas/steam turbine.
The CO2 is used for oil recovery, with any associated gas produced separated and recycled back into the process. Clean Energy Systems, says the steam could also be used for assisted gravity drainage or cyclic/constant steam floods.
|A TriGen unit during combustion|
CO2 EOR would be well suited to MENA reservoirs, says Alford, with 47% of the worldwide CO2 EOR potential in the region, according to a 2010 paper by Michael Codec.
Alford says CO2 water alternating gas injection has the potential to be 50% more efficient than methane gas injection or convention water flood, increasing rates from 30- to 50%.
“It is important to note that these are barrels not recoverable by any other means,” says Alford. “This is fully incremental oil. Water flood, methane gas injection, will not get you this oil.
“The CO2 dissolves into the oil and creates miscibility, and gives energy to the oil, which means you can get a better sweep of the reservoir,” says Alford. “Depending on how much CO2 you use, recovery could theoretically be up to 100%.
“One thing we are looking at is, do you really need 99.9% pure CO2? You can also get miscibility with nitrogen if reservoirs are deep enough. For the reservoir’s here we expect 95% purity CO2 to be adequate.”
However, it’s not a one size fits all solution. EOR using CO2 is more suited to light oil, than heavier oils, where steam would be a better option. A unit onshore would cost about US$400 million, including the air separation plant, says Alford.
“We are working on different size units that require from 25-45MM cf/d of gas and produce up to 200MW of power. Water production can be tuned, so is about 0.5MM imperial gallons/d per unit.
“Reservoir size is dependent on how long the injection would continue for. We would need a reservoir of about 400MM bbl originally in place to operate for 20 years with our biggest unit. CO2 production is almost the same amount as the inlet fuel gas.”
On one plant, 40-50 MM cf/d fuel gas would be combusted with double the amount of oxygen, at nearly 2000°C. This produces about 160-180 MW power, and 40-50MM cf reservoir-ready CO2, and about 500.000 gallons/day of pure water.
Alford says one gas generator would be the size of two shipping containers, however, the air separation unit, which has not yet been optimized for offshore use, currently covers a larger area.
“Offshore, you may require a separate platform for the air separation plant, for process safety.”
A laboratory-scale plant was created in 1995, followed by a 40MW demonstrator plant in 2005. The first commercial scale unit, at 150MW, was built in 2012, in Bakersfield, California, by partner Clean Energy Systems.
Siemens is a partner on the project, to provide the turbine. The US department of Energy provided US$30 million funding for the first plant.
Maersk has proposed an onshore site for a Trigen plant at Mirfa, which could supply CO2 via pipelines to offshore fields in shallow water, or to onshore fields. Oxygen created in an existing nitrogen production process onshore, and currently vented, could be a source of supply.
|An artist's illustration of the system installed onshore|
Deployment of one unit could be within three years, with further units in three year execution intervals. Masdar has proposed CO2 pipelines running between onshore fields, at coastal points, where pipelines could be landed.
“We are engaging with ADNOC and Masdar,” says Alford. “We are currently in discussions to get a unit in the field, and it would take a three year execution period to build a full project with a turbine lead time of one year.”
The Bu Hasa field is a potential future candidate subject to ADNOC requirements. It could accommodate 20 units, says Alford. It still has over 20Billion bbl recoverable.
“Kuwait, Saudi Arabia, Oman, they are needing all these products, CO2, water, and power,” says Alford. “We also have a lot of interest from Malaysia and Indonesia, where they have naturally occurring CO2 in the gas. Because we are burning with oxygen, it is the best oxidizer out there. You do not need to do any pre-separation of CO2, and can utilize low value gases.”
images courtesy of Maersk Oil