Oilfield Technology Correspondent Gordon Cope shows how North America’s oil and gas industry is growing from strength to strength.
Much work is being done to address fossil fuel-related issues. The governments of Alberta and Canada recently contributed C$ 865 million to Shell’s Quest project. Starting in 2015, Quest will capture more than 1 million tpy of CO2 from Shell’s Scotford upgrader near Edmonton. It will then be transported 65 km and injected underground into an oil reservoir as part of an EOR project. Efforts are underway to reduce the amount of energy needed to coax bitumen out of the ground by experimenting with fire-fronts, solvents and electromagnetic waves. Innovative catalysts are being tested to partially upgrade the bitumen while it is still in the reservoir, reducing its viscosity.
Issues surrounding hydraulic fracturing are also being addressed. The Environmental Protection Agency (EPA) will examine the full cycle of frack water, from acquisition to mixing and post frack stage (where produced water must be managed and properly disposed). Fracking companies are devising new chemicals made from benign household products and food ingredients, and reducing the amount of water used. Service companies are building portable modules to recycle frack water that returns to surface.
Industry has been promoting understanding of the practice through education efforts and public announcements. In 2013, the Petroleum Services Alliance of Canada (PSAC) issued the Hydraulic Fracturing Code of Conduct for its members (which include all Canadian frack services companies). Members of PSAC agree to follow five key standard practices and goals: water and the environment, fracturing fluid disclosure, technology development, health, safety and training and community engagement.
Operators are looking to export natural gas in the form of liquefied natural gas to energy-poor countries like Japan that are willing to pay a premium. Shell and Southern Liquefaction received approval to build the Elba Island LNG terminal near Savannah, GA. The facility will have a total liquefaction capacity of approximately 2.5 million tpy. ExxonMobil, BP, ConocoPhillips and TransCanada have announced preliminary details to ship up to 18 million tpy of LNG from Alaska to Asian markets from their proposed facility on the Kenai Peninsula.
In Canada, the NEB has approved nine LNG facilities on the west coast of British Columbia to ship gas to Asia. Among the projects, EnCana, Apache Canada and EOG Resources received approval to build the C$ 5.6 billion Kitimat LNG project, capable of liquefying 1.4 billion ft3/d. Royal Dutch Shell, Korea Gas, Mitsubishi and China National Petroleum Corp. are also contemplating the LNG Canada project, a Kitimat facility that would convert 1.8 billion ft3/d. BG Canada has proposed the Ridley Island LNG project that would handle 4.2 billion ft3/d in Port Rupert, BC.
Faced with stiff opposition to Keystone XL, pipeline companies are seeking alternative routes. Enbridge has plans to expand deliveries to Quebec; it has been given approval by the NEB to reverse Line 9B, which delivers crude from Quebec to Sarnia, Ontario. The reversal will allow the company to deliver up to 300 000 bpd of heavy oil and lighter Bakken crude to refineries in the Montreal region. TransCanada is looking to repurpose its Mainline gas transmission system running from Alberta to Ontario, then to extend it with new-build. The 4500 km Energy East pipeline would deliver up to 1.1 million bpd from Alberta to the deepwater port of St. John, New Brunswick.
Canadian and American operators in the oilsands and the Bakken are increasingly relying on rail to get to market. Currently, approximately 180 000 bpd travels by rail, but the Canadian National Railway (CN), Canadian Pacific Railway (CPR), and other US firms are building tanker loading facilities and devising crude-only trains that exceed 100 tankers in order to lower transportation costs. Analysts now expect crude-by-rail capacity to exceed 1.1 million bpd in 2014.
In addition to Canada’s stymied efforts to find new routes to market for increased bitumen production, American producers face their own dilemma. Since the early 1970s, they have been confronted by a virtual ban on crude exports. The instigation of the ban was a result of events surrounding the Yom Kippur war in October 1973. When Syria and Egypt launched a co-ordinated attack to regain land lost in the 1967 Six Day War, the US came to Israel’s aid with arms supplies. Some members of OPEC decided to retaliate with an oil embargo against Canada, Japan, the Netherlands, the UK and the United States.
By 1974, the Nixon Administration had negotiated troop withdrawals and a cessation of hostilities, and the embargo was withdrawn. The action itself, however, had much farther reaching effects. OECD consumers faced massive fuel line-ups and price rises. The US, which was challenged by both rising consumption and falling production, was especially hard-hit. In 1975, Congress passed the Energy Policy and Conservation Act (EPCA) that sought to decrease dependency on foreign oil through conservation and energy diversification to coal, nuclear and natural gas.
In addition, the EPCA restricted the export of US crude unless a licence was granted for that purpose. Those seeking to export had to approach the Department of Commerce’s Bureau of Industry and Security (BIS) and apply under the Short Supply Controls guidelines. The result was a virtual cessation of exports of US crude.
Although the US will still have to import oil for many years to come, its current supply growth in the Eagle Ford and other unconventional plays is largely comprised of light, sweet crude. Gulf Coast refiners have limited ability to process the crude, and there is a growing chorus to lift the export ban. Recently, IHS released a report (commissioned by energy companies including Exxon Mobil Corporation, Chevron Corporation and ConocoPhillips) that concluded that lifting the ban would result in US$ 1 trillion to government revenues through 2030, trim fuel prices, and add an average of more than 300 000 jobs a year.
“Additional exports could prompt higher production, generate savings for consumers, and bring more jobs to America,” said Kyle Isakower, the API’s vice president for regulatory and economic policy, in a prepared statement. “The economic benefits are well-established, and policymakers are right to re-examine 1970s-era trade restrictions that no longer make sense. Of course, some will continue to argue that limits on trade are in the interests of consumers. But these arguments ignore the simple fact that consumers buy fuel – not crude oil – and the prices of refined products are set by a global market. Gasoline is already eligible for trade after oil is refined. Restricting the flow of America’s growing crude supplies only puts downward pressure on US energy production – not prices at the pump.”
In spite of all the tribulations, North America’s oil and gas industry continues to move from one promising unconventional play to the next.
Recently, attention has focused on the Cline formation, which lies in the Permian basin in west-central Texas. Initial tests have indicated that the shale, which ranges from 200 - 550 ft in thickness, holds an average of 3.6 million bbls of light, sweet recoverable oil per square mile. All in all, the Cline shale may hold an estimated 30 billion recoverable bbls, 50% more than the Eagle Ford and Bakken plays. Recently, Apache spent US$ 7.6 million drilling a 6800 ft lateral with 15 hydraulic stages. The estimated ultimate return is 423 000 boe, of which 87% is liquids.
No one doubts that North America’s oil and gas industry has tremendous potential, but it also faces significant challenges that need to be addressed. It will have to spend billions of dollars re-aligning existing energy transportation networks to take into account the growth of new sources, while at the same time communicating to the public that it is doing so in a safe manner. It must continue to reduce its environmental footprint and meet ever-stricter regulatory rules. It is obligated to seek out new international markets for its products while ensuring consumers at home that they will not face undue financial hardships. Doing it all correctly will not only impact the continent’s energy future, but will have an unprecedented effect on the world as well.
Read the article online at: https://www.hydrocarbonengineering.com/special-reports/15102014/boom-not-bust-part-2/