Laura Atkins has more than 20 years' experience in the oil industry. She has worked for Arco and Amoco and served as a senior research analyst for OPEC before joining Hart Energy Consulting.

The first Heavy Oil study was produced in 2007 and focused on North America. The 2008 update now presents a global heavy oil analysis and outlook. It reveals the role of heavy oil in the overall world energy supply over the next 20 years and incorporates both upstream and downstream information. Integrating up- and downstream activities is particularly important for heavy oil as operators need to know that there is refining capacity for their production and refiners need to know what will be coming their way in the future.

North America

The report outlines some changes in North America since 2007. A number of projects have been delayed, sometimes by several years. Rising costs, changing taxes and regulatory environmental issues such as greenhouse gas (GHG) emissions are the most common reasons given for delays, although most projects are expected to move forward. GHGs are a challenge that the heavy oil industry must address. In addition, regulators need to outline a clearer direction, because it is uncertainty that is leading some companies to delay projects until they can better understand the requirements.

Interest in Canadian heavy oil remains high, with many international players buying into the country’s acreage. Canada is widely seen as the global technology leader, and several Canadian oil sands technologies are now starting to be applied elsewhere, such as SAGD pilot projects in Russia. Canada is, however, expected to provide the biggest increases in production rates, having established the momentum to stay ahead of the rest of the world.

There is indication of renewed interest in developing bitumen deposits in the United States. These are heavier and more dispersed than the Canadian deposits. Operators in Alaska plan to increase heavy oil production from the North Slope.

Mexico has been the major supplier of heavy oil to North America for many years. Production is declining rapidly and will continue unless more reserves are discovered. Nevertheless, Mexico will remain a significant heavy oil producer for several years.

South America

Brazil will need very different strategies to those applied in Canada to address its offshore heavy oil resources; these are lighter than Canada’s tar sands but still qualify as heavy oil. Here, extended-reach horizontal wells and non-thermal methods such as water or gas injection are being used to extract heavy oil located under deep water. New technologies highlighted in the report could, in the future, be used to enhance recovery.

In the Orinoco basin, Venezuela, primary production is considered sufficient for most of its foamy oil reserves, though higher recovery levels could be achieved using thermal methods. Here, more effort is being focused on upgrading technologies for refineries, such as the hydrocracking distillation hydrotreating (HDH) process.

The report details the geographical extent of active heavy oil projects, finding pilot projects in progress in Colombia and Peru. Ecuador has heavy oil under a UN Biosphere Reserve site, which, if developed, would require extra attention to the environment.  Some heavy oil reserves exist in Argentina, but there is little development effort.

Central Asia

Kazakhstan is focusing on developing light oil. China, however, is a different story; here there are considerable reserves and a high level of interest in developing all available deposits. Some 70% of China’s proven reserves are heavy oil, though only 13% of current production. Most reserves are shallow and onshore, so suited to thermal methods, and China has several steam flood projects that have been producing since the mid-1980s. Some heavy oil deposits are too deep for current steam injection processes, so alternative methods are being considered for heating the reservoir, such as polymer injection and the electric heating systems being developed for oil shales.

Rest of the world

In the North Sea, in areas such as West of Shetlands, high oil prices are encouraging operators to bring several small fields into production up to 15 years after their discovery. Norway is producing the Grane heavy oil field, making it currently the largest heavy oil producing country in Europe.

Russia is mainly focusing on its light oil, and no major heavy oil projects are expected in the next few years in the main oil producing regions; however, pilot projects are beginning in areas such as Tatarstan and in the Timon-Peshora basin. Small scale field developments are expected within the timeframe of the report.

In Africa, most of the current heavy oil activity is offshore Angola, where new reserves are being discovered and brought into production. Large bitumen deposits are located onshore in Egypt, Nigeria and Angola but there are no firm plans to develop them at this time. Madagascar has significant heavy oil and bitumen deposits and the country is very interested in developing them, particularly as it has few other hydrocarbon reserves. Australia produces heavy oil from two small fields. Most of the new projects are light oil or natural gas, and it is unlikely that it will become a significant heavy oil producing area.

The Middle East has over 900 billion barrels of discovered heavy oil resources, most of which are undeveloped. Kuwait is particularly keen to ramp-up production and has set a target of 900,000 bbl heavy oil per day by 2020, including their share of production from the PNZ. Steam injection is the preferred technology, but there is a lack of fresh water means and the cost of desalination significantly impacts operational economics and adds energy usage and GHG emissions.

Hurdles to growth for heavy oil are much the same as for conventional oil production, but environmental issues are even more significant. GHG emissions from production and refining are double those for conventional oil production. However, it is important to compare GHG emissions with other non-conventional sources, such as oil shale and coal to liquids (CTL), which are considerably higher (CTL emits twice the GHGs as the most energy intensive bitumen process). In Canada, the pressure to reduce GHG emissions may provide additional incentives to build new upgraders. Integrated upstream/upgrading projects have the capability of reducing both natural gas consumption and to capture CO2 for injection underground (sequestration). This requires significant investment, but there is growing realization that the causes of climate change need to be addressed.

Finding an adequate supply of diluents can represent another hurdle where pipeline transport is required. Canada is building a diluent pipeline from the US to Canada, but in many cases, local partial upgrading near the well may be preferable to sending diluent to the wellsite.

The report summarizes the major components of costs in different regions. Fiscal regimes are discussed in detail only where they are known to be a major issue or where they have recently changed or are expected to change. An example is the recent increase in royalty on Canadian oil sands, and how this is expected to affect development plans. In many countries, fiscal terms are project-specific and are established through negotiations between the government and the contractor.

Looking ahead to the next 10 to 20 years, global production of light and medium crude oils will remain flat while heavy oil and non-conventional crude production will grow slowly. Demand will continue to increase. The balance between crude supplies and demand will be met by gas liquids, with small contributions from biofuels, GTL and CTL. Qualitatively, the report concludes that global average liquid supplies will not become heavier because it will be balanced by a higher portion of condensates and natural gas liquids. However, in some regions, additional heavy oil refining capacity will be required to handle the higher volumes.

Many peak oil theorists predict that conventional crude oil will soon peak and start to decline. If so, in around 20 years, heavy oil will become increasingly important to global crude supplies. With heavy oil, once a project is fully developed, it will usually produce at a plateau rate for many years, but it is difficult and costly to accelerate production. Most heavy oil production processes are slow; it heats slowly and flows slowly. There are exceptions, however, such as offshore Brazil where horizontal wells are able to produce at high rates for about 15 to 20 years, after which operators may go back to produce the oil left behind if the price will support the cost. There are opportunities for lengthy tail production where operators can go back in, but this may be difficult in deep water.

Technology is the big enabler that will facilitate change. For example, if the new processes such as toe-to-heel-air-injection (THAI®), vapor extraction (VAPEX), or electrical heating prove successful on a commercial scale, then the scenario could change significantly. Several alternative technologies suitable for deeper reservoirs are now being tested, such as injecting lighter hydrocarbons as a vapor, either on their own or with steam to make steam use more efficient. In Alaskan shallow reservoirs an immiscible rich water-alternating gas (WAG) scheme is being tested, where the gas is intended to swell the cold viscous oil enough to enable enhanced production by water sweep. The technologies being tested are at various levels of maturity, some are involved in pilot projects while others are still in the laboratory.

There are several interesting new prospects. Parts of Russia, China, and Syria have great potential, as does Madagascar where heavy oil development is new and reasonable terms are being offered to develop resources. Colombia and Peru have undeveloped heavy oil resources and are improving their fiscal terms to encourage international investment. In Canada in the province of Saskatchewan, vast heavy oil resources are only beginning to be delineated. Most, but not all, of the acreage likely to give a good short- to medium-term return is already under development. Water is becoming an issue in Alberta, and restrictions on its use may keep companies from staking out bigger claims in the next few years. Saskatchewan and British Columbia offer many good opportunities and have different regulatory regimes to Alberta

Can you buy the report?

Atkins states that, for operators with interest and/or expertise in heavy oil, the new report will point them towards new opportunities, including the resource potential, refining and disposition of heavy crude, and the technologies that may allow new and more challenging heavy oil developments in the future. It provides more than just data; it also offers integrated analysis that tries to pull it together, linking upstream to downstream. It gives companies an overview of the future of heavy oil and information useful to the strategic planning process.

Further information, and ordering details for Heavy Crude Oil: A Global Analysis and Outlook and other reports can be found here: http://www.hartwrfs.com/heavycrudeoil.php.

Alternatively, contact Glenn Dubin gdubin@hartenergy.com.

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