CALENDAR OF EVENTS & NEWS
- 09.07.10 - Fall Conference REGISTRATION FORM (printable)
- 09.07.10 - Fall Conference REGISTRATION FORM (online)
- 09.01.10 - ERCB 2010 Shale Gas Fluid Codes
- 09.08.10 - Technical Luncheon Series - J Harder
- 09.15.10 - CSUG Golf Tournament
- 09.15.10 - 3rd Symp. on Resource Assessment Methodologies
- 10.19.10 - CSUG/SPE Technical Conference, October '10
- More...
| UCG Facts |
The Four Types of Unconventional Gas:
General Energy Facts
Unconventional GasNatural Gas from Coal (NGC) or Coalbed Methane (CBM)
Regulation of the IndustryEnvironmental Considerations and Concerns
Compressors
Shale Gas
Tight Gas Sands
Gas Hydrates
General Energy FactsEnergy Facts – OverviewCanada is rich in natural gas and petroleum resources. Both crude oil and natural gas are found in sedimentary rocks formed over millions of years by the accumulation in sedimentary basins of sand, silt and the remains of plants and animals. (Page 5, Our Petroleum Challenge) Today, Canada produces more oil and natural gas than Canadians consume. As a result, the selling of our resources to other countries, primarily the U.S., is a major contributor to Canada’s economy. (Canada is the largest foreign supplier of natural gas to the U.S.) In 2001 alone, Canada exported energy products worth $55.1 billion, which represented 14% of all exports. (The Daily, Statistics Canada, October 27, 2004) In addition, indirectly and directly, the oil and gas industry employs more than half a million Canadians and also contributes, through taxes, royalties and other payments to government, to health care, education and social programs. From 2000 to 2003, the industry paid an average of $14.4 billion annually to governments. (Page 17, Our Petroleum Challenge) Although Canada is still a major producer of natural gas, there is now a focus in the industry on exploring for, and developing, natural gas from unconventional resources. This is because the production of conventional natural gas peaked in 2000 and has been decreasing ever since. New gas finds are therefore needed every year to offset a 20 per cent natural decline in production. With demand remaining strong, unconventional gas will have an important role to play in reducing the gap between demand, and declining conventional gas production. What do we use energy for in Canada?Seventy per cent of the energy consumed by Canadians is provided by natural gas and oil. For example, we use natural gas in the plastic components of computers, telephones, TVs, etc.; heating our homes and producing hot water (about 20 per cent of Canadian natural gas usage is for home heating); generating electricity (one of the fastest-growing uses of natural gas, 27% of energy demand is for electricity); and as a key raw material in the fertilizer and petrochemical industries. How much energy do we use?Canada’s geography, weather and widely-distributed sparse population create a unique situation. Canadians use more energy than most other countries, especially countries with large populations compacted into a small area. Our weather requires us to use energy to heat our homes in winter, to provide light during the long winter nights, and to cool our homes and businesses in hot summer weather. Our resource-based economy also relies on energy-intensive industries, such as: mining; petrochemicals; steelmaking; refining; forestry; and pulp and paper. In addition, we require energy to move goods from one area to another in our large and sparsely populated country. Although we may consume more energy than many other countries, our carbon emissions per person are 12.5 per cent less than that of the United States because a large part of our electricity comes from hydro and nuclear power and much of the fuel used in industry, commerce, and residences are provided by low-carbon natural gas. Why don’t we use renewable energy sources to replace declining natural gas production?The potential for renewable energy to provide long-term sustainability and environmental benefits is extremely appealing. Unfortunately, there are no known renewable sources that can significantly offset the demand for natural gas in the foreseeable future. Natural Resources Canada predicts that between 1995 and 2020, energy from renewable sources will increase by 527 PJ or 21 PJ per year [Energy in Canada – 2000]. However, Canada uses nearly 10,000 PJ per year [Statistics Canada, 2003] and must replace approximately 900 PJ every year due to declines in oil and gas production [calculated by CSUG based on Alberta ERCB data and the Canadian hydrocarbon energy demand from Statistics Canada]. Even with significant technical breakthroughs and expected increases in Renewable Energy investment, natural gas is expected to be an increasing contributor to Canada’s energy supply. Sources: Unconventional GasWhat is unconventional gas?Unconventional gas is simply natural gas that is contained in “difficult to produce” rock formations, which require different or special completion, stimulation, and/or production techniques to retrieve the resource. Natural gas from coal (NGC) also known as coal bed methane (CBM), or in British Columbia as coalbed gas (CBG), along with tight sands, shale gas, and gas hydrates are all examples of unconventional gas. In the past, technical challenges and cost issues around producing unconventional gas deterred resource exploration and development. However, as conventional gas resources are becoming depleted and the need for energy has increased, the necessity for developing alternate resources has become important. Although production of unconventional gas in Canada is very recent, it is anticipated that by 2025, unconventional gas will account for about 80 per cent of new drilling and 50 per cent of total gas production. The goal of Industry is to responsibly develop this resource while taking into consideration the social, economic, and environmental impacts of development. Source: CSUG Strategic Priorities document For more information on unconventional gas, see Centre for Energy Why do we need unconventional gas?Our known conventional sources of natural gas in North America are declining rapidly. According to the National Energy Board (NEB), gas production in Canada peaked at 17.5 billion cubic feet per day (bcf/d) in 2001, and has been decreasing since then. “New gas finds are needed every year simply to offset a 6.5 per cent natural decline rate in production from existing wells”. With demand for natural gas expected to remain strong for the foreseeable future, most, if not all of the available new supply sources will be required (such as Arctic gas, imported Liquefied Natural Gas (LNG), Alaskan gas, Nova Scotian gas, and CSNG) to meet consumer demand in North America. Industry and government see NGC as having an important role to fill in reducing the gap between future demand and declining conventional production. If this gap is not reduced with new sources of natural gas, we could see an increase in the consumption of other less cleaner fossil fuels and/or increases in the price of natural gas.  Projected Annual Natural Gas Production from United States Natural Gas from Coal (NGC) or Coalbed Methane (CBM)What is natural gas from coal?Natural gas from coal (NGC), coalbed methane (CBM), or coalbed gas (CBG, in British Columbia) is simply the natural gas found in most coal seams. Methane is the principal component of natural gas. CBM is created during coalification, the natural process that converts organic matter into coal over time. A seal created by overlying rock and/or water within the fractures of the coal seam keeps the methane 'adsorbed' or attached to the coal. Like conventional natural gas, NGC is a cost-effective and clean-burning fuel that has many applications, such as heating your home. It is generally considered to be more environmentally friendly than oil or coal and requires minimal processing. NGC has a resource base comparable to the remaining undiscovered conventional resources of Western Canada. In a recent NEB draft publication on “Canada’s Energy Future”, it estimates Western Canada Sedimentary Basin (WCSB) undiscovered potential at 71 to 99 trillion cubic feet (tcf) of natural gas. The chart below, compiled by the Canadian Gas Potential Committee, estimates the NGC resource to be between approximately 150 to 500 tcf in place. Recent estimates by the NEB suggest that NGC could contribute up to 3 bcf/d to Canada’s natural gas production.  Source: Exploration and Development of Natural Gas from Coal (NGC) in Canada – Facts and Issues, produced by CSUG 2003. For more information on: Coalbed gas in BC (FAQ on coalbed gas in BC), please visit BC Ministry of Energy and Mines Why are different names used for this resource?
Whatever name is used, it is all the same thing: natural gas that is produced from coal seams. Source: Natural Gas from Coal fact sheet – CSUG How is natural gas from coal produced?NGC is produced by reducing the natural pressure within the coal seam, which allows the gas to release from the coal and flow through the coal seam to a well, and then up the well to the surface where it is compressed and transported through natural gas pipelines. Typically, a steel-encased hole is drilled into the coal seam. Next, the coal seam is fractured by injecting fluid (typically water-based foam and sand or an inert gas such as nitrogen) down the well and into the seam's 'cleats' or natural fractures. This opens the cleats and creates channels through which the NGC can flow. If required, the coal seam is then de-watered. De-watering removes water that naturally exists within the cleats of the coal. This reduces the pressure in the coal seam and allows the gas to flow into the well bore and up to the surface. The gas is then collected and compressed into a pipeline to be shipped to your home. Source: Exploration and Development of Natural Gas from Coal (NGC) in Canada – Facts and Issues, produced by CSUG 2003. For a description of drilling for and the testing of an NGC well, see Centre for Energy Where is NGC/CBM found in Canada? As of 2008, Alberta is the only province with commercial production of NGC, although there is potential in many parts of British Columbia, Saskatchewan and Nova Scotia. Who regulates the NGC Industry in Canada?Regulations are provincially controlled. NGC operators are subject to all the same strict regulations contained in provincial and federal wildlife and environmental laws as are conventional oil and gas operators. Currently, NGC exploration and development comes under the same regulations as conventional oil and gas in all jurisdictions, although British Columbia has recently introduced some NGC/CBM specific regulations. NGC activities are reviewed by the energy, environment, and other associated ministries within the provinces of Alberta and B.C. Producers of NGC are subject to federal and provincial wildlife and environmental laws, as well as extensive Industry-specific rules from regulatory agencies. These rules cover every stage of the development, including reclamation of well sites. In Alberta and British Columbia, the regulators ensure consultation occurs with affected stakeholders and governments, including First Nations, before development begins. And regulators enforce strict compliance measures once a project is underway. Source: Exploration and Development of Natural Gas from Coal (NGC) in Canada – Facts and Issues, produced by CSUG 2003 Alberta
British Columbia
New Brunswick Nova Scotia Saskatchewan Environmental Considerations and ConcernsWhat are the Environmental considerations regarding natural gas from coal production?Stakeholders have raised concerns about NGC development and the impact it has on the environment. Some of these issues are related to: well sites/pad sizes, well density, flaring, water management, noise concerns, wilderness and wildlife impacts, and plugging and abandonment concerns. In all provinces, regulations exist to govern the Industry’s practices with respect to these concerns. For details specific to any individual location, please contact that province’s energy or natural resources departments or oil and gas regulatory agency. Well sites and pad sizes Well site “footprint” – the initial footprint of an NGC well depends both on the depth and type of completion practice being employed. A single well lease site for a shallow sweet conventional or unconventional gas well such as NGC, will typically consist of an area measuring 100 metres by 100 metres. Since NGC wells are often shallower than conventional gas wells, smaller rigs with smaller corresponding surface lease areas are generally requested by Industry. Once NGC drilling is complete and the well is connected to the pipeline, much of the leased land can be used for its original purpose. Later, some of the area can be re-vegetated and re-contoured, leaving little long-term impact. Eventually, the entire site will be reclaimed and restored. Source: Exploration and Development of Natural Gas from Coal (NGC) in Canada – Facts and Issues, produced by CSUG 2003 Well density Because individual NGC wells are likely to be less productive than the average conventional gas well, the NGC gas fields may require a higher density of wells to efficiently extract the natural gas. Current conventional natural gas well density varies from one to sixteen wells per section (one square mile). It is expected that, in most areas, a typical NGC development will require between two and eight wells per section. Successful experimentation with different drilling and completion technologies such as directional and horizontal drilling could result in reducing well density (i.e., less surface locations per section). Source: Exploration and Development of Natural Gas from Coal (NGC) in Canada – Facts and Issues, produced by CSUG 2003 How does industry minimize flaring? Because flaring results in the loss of a saleable product, Industry does everything it can to minimize flaring. In the case of NGC, flaring is only done during well testing or for a brief time during the start-up of a well when the gas contains too much nitrogen to be sold. The flaring period depends on the rate of gas flow and the proximity to pipelines, but does not typically extend beyond a week, except for initial evaluation operations in some new development areas. Since NGC gas is sweet, flaring is not a safety or health concern as is found in sour gas production. Source: Exploration and Development of Natural Gas from Coal (NGC) in Canada – Facts and Issues, produced by CSUG 2003 Current flaring regulations In provincial jurisdictions, flaring is governed by provincial bodies. In Alberta, the Alberta Energy and Utilities Board (ERCB) regulates flaring and venting according to the methods outlined in its Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting Public notice of any extended flare testing is required. In British Columbia, All flaring activities require approval from that province’s Oil and Gas Commission (OGC). Information is available on the web for the Clean Air Strategic Alliance What are the concerns related to water and drilling coalbed seams?A challenge with many NGC developments outside of Alberta is the potential for production of non-saline water along with the gas. However, in Alberta, this is much less of a problem, as most of the coals that are capable of producing NGC do not contain non-saline water. De-pressuring a coal seam can produce water of varying quality and volumes. NGC-produced water is simply the water that is found within coal seams. It is naturally occurring; its quality can be saline or non-saline. To date, little non-saline water has been produced in association with NGC development in Alberta. There are three general scenarios with water production and NGC:
Contrary to experiences in other basins, early indications suggest NGC production in Canada may not generate the volumes of water produced elsewhere. For example, there is significantly more water produced with the gas in the Powder River Basin in Wyoming than elsewhere. In many parts of Alberta, NGC production has no associated water. However, produced water remains an environmental and economic consideration, which must be managed from a technical and regulatory perspective, and will be part of any decision regarding the ultimate development of this resource. In Alberta and BC, regulation requires that the saline water produced be injected into deep underground formations. These underground formations are deep and not connected to any non-saline water sources. Injection poses no threat to groundwater, fish habitat or local vegetation because the wells used for disposing of these waters are carefully constructed to protect groundwater and are closely monitored and regulated by the regulators. Deep injection of saline water has been practiced around the world for many decades. Non-saline water produced with NGC will require special approvals from the regulator to ensure the maximum amount of usable water is conserved without causing environmental damage. The production, use and disposal of all water in Canada is rigorously regulated. In 2007, the government of British Columbia introduced enhanced standards requiring no surface discharge of produced water from NGC wells in that province. Source: Exploration and Development of Natural Gas from Coal (NGC) in Canada – Facts and Issues, produced by CSUG 2003 What are the current regulations on groundwater protection?Regulations vary from jurisdiction to jurisdiction and readers must check for specific regulations for each province or regulator. Groundwater protection is under the jurisdiction of provincial agencies. Handling saline water Any saline water that is produced during gas production must be returned to a similar underground environment through deep disposal wells. Water disposal is provincially regulated. The ERCB regulates the production, handling, and use of water produced in association with natural gas, oil, and bitumen in Alberta. Handling non-saline water In Alberta, if non-saline water is produced with gas, in addition to ERCB regulations, it must be handled according to regulations set out in the Water Act. The producer must be authorized by the Department of Environment to use, divert, or dispose of any non-saline water before the wells are drilled. Before authorization is granted, adjacent property owners, who would be impacted by the development, must be informed of plans to handle the water. As of August 2008, Alberta Environment is in the process of reviewing regulations related to non-saline water. Aquifer protection When drilled, an NGC well could pass through several groundwater aquifers. Well casing is cemented in place to protect groundwater aquifers. Well drilling, completion, and production requirements address how drilling fluids are handled, and prevent mixing water from different zones. These requirements are dictated and performance-monitored by the regulator. Hundreds of thousands of oil and gas wells have been drilled in Alberta without incident. For more detail, please view the Coalbed Methane Wells and Water Well Protection Document. Source: Alberta Energy website Links: Compressors
Why are compressors necessary in the extraction of natural gas from coal?Virtually all natural gas from coal produced requires compression in order to prepare the gas for entry into the natural gas pipeline system. NGC involves low pressures and usually requires several stages of compression. Source: Exploration and Development of Natural Gas from Coal (NGC) in Canada – Facts and Issues, produced by CSUG 2003 What can be done to manage compressor noise?Where noise is a problem, compressors can be located to minimize the noise disturbance. Special baffles and mufflers can also be installed, if required. Source: Exploration and Development of Natural Gas from Coal (NGC) in Canada – Facts and Issues, produced by CSUG 2003 What is different between the Canadian NGC experience and the American experience?Generalizations and comparisons between U.S. and Canadian NGC development cannot be made confidently. Many people have formed opinions on NGC based on information obtained from U.S. CBM operations. But not all NGC fields are the same. In fact, we often say no two NGC fields are alike. This may be one of the reasons Canada has lagged in NGC development. To date, Canadian coals have many characteristics different from those found in the US. Given the significant differences between Canadian NGC developments and current U.S. operations in Wyoming’s Powder River Basin or any other basin, it is inappropriate and misleading to make direct comparisons. Many U.S. CBM operations commenced two decades ago, in areas where regulations and awareness of the impact of some oilfield practices were not as well understood as they are today. Current provincial regulations enforce stringent requirements on Industry in Canada before NGC development can proceed. Canadian communities and NGC producers can benefit from the U.S. CBM experience. Stringent regulatory and environmental standards will ensure that NGC development is conducted in an environmentally responsible way. Current experimentation with different technological applications may significantly reduce surface impact. Another NGC challenge is the number of wells required in some areas because there is so little natural pressure pushing the gas to the surface. New drilling and completion technology holds the key to reducing the number of required NGC wells. In Canada, regulators control the number of wells per section, and the rules are the same for NGC as for conventional gas well drilling. Source: Exploration and Development of Natural Gas from Coal (NGC) in Canada – Facts and Issues, produced by CSUG 2003 Shale GasWhat is shale gas?Shale gas is natural gas stored in organic-rich, very fine-grained rocks such as shale, mudstone or laminated siltstones. The natural gas molecules are held in the reservoir rock by the process of adsorption onto the organic matter. The shale can be the source as well as the reservoir. The natural gas can be derived from either thermal or biogenic processes. Why is shale gas considered to be an Unconventional Gas Resource?Shale gas is considered to be an unconventional gas source as the gas is contained in difficult-to-produce reservoirs. In shale reservoirs, the permeability (the ability to flow hydrocarbons) of the rock is very low, and stimulation techniques must be employed to intersect and create fracture pathways that will allow the gas to flow to the well. Recent success of commercial shale gas development in a number of basins throughout North America can be attributed to the application of advanced technologies that are used to drill and stimulate the shale-bearing formations. How is shale gas produced?Shale gas is produced in much the same way as conventional reservoirs. Due to the low permeability inherent in gas shales, stimulation is almost always required. Fracturing the shale is required in most situations to achieve economic production. In the U.S., vertical gas shale wells have proven to have fairly low production rates with a long well-life with fairly low recovery rates. This means that drilling and completion costs have to be kept to a minimum to be economically viable. Technologies continue to be developed to increase the recovery percentage and effectively stimulate the shale at minimal cost. Shale gas can be produced from vertical, angled or horizontal wellbores. Where vertical or angled wells are drilled, commonly individual sections of the shale formation that have been intersected in the well are stimulated, and then the gas is commingled to yield economic gas production (Figure 1).
To overcome the low permeability reservoir conditions, and hence lower well productivity, horizontal drilling and multistage fracture stimulations have been developed, particularly in deeper wells where well costs are dramatically higher. In deeper horizons, horizontal wells are drilled to optimize the amount of gas- bearing shale intersected. Upon completion of the drilling of the horizontal portion (commonly referred to as the leg) of the wellbore, production casing is placed in the borehole. The casing is then perforated in selected locations and then fracture-stimulated. Fracture stimulations require substantial amounts of water and sand to “crack” the shale and allow the gas to flow to the wellbore. A new technology that has enabled many shale reservoirs to become economically productive entails the use of staged fracture stimulations. This technique separates the horizontal leg into stages that are separated by plugs or packer systems. The fracture stimulation can then be concentrated into a specific stage. Each stage is fractured separately, then the plugs or packers are removed, and the gas from the entire horizontal leg can flow up the production tubing to surface (Figure 2).
Where is shale gas found?Shale gas can be found in most sedimentary basins in North America where conventional natural gas resources currently exist. In many cases, the shale- bearing formations are the source of the natural gas that is being produced from conventional reservoirs. The volume of gas present is dependent on a number of variables such as organic richness, thermal maturity, and depth and pressure. What is the history of shale gas in the U.S.?Gas shale has a long history in the U.S. By 1926, the Devonian shale of the Appalachian basin was in commercial production and was the largest known natural gas field in the world. These shales still account for the majority of gas shale wells in the U.S. with over 21,000 wells producing. (Source: Shirley. 2001.) While the gas production potential of gas shales has been known since the early 19th Century, commercial development of gas shales in the U.S. took off largely as a result of a non-conventional fuel tax credit implemented in 1980. The tax credit expired in 1992, but with the application of new drilling and completion technologies, numerous basins containing shale gas resources are being developed. Currently, gas shale resources are being developed in the Fort Worth Basin in east Texas, the Fayetteville area of Oklahoma, the Haynseville region of Louisiana, the Woodford play in Oklahoma, the Marcellus play in New York and Pennsylvania, and the deep shale play of the Palo Duro basin in Texas (Figure 3). Current shale gas production exceeds 4 bcf/day with the Barnett shale play of the Fort Worth Basin contributing over 3 bcf/day. Many companies are expanding their shale gas exploration and development activities, and significant growth is occurring in a number of shale basins in the southern states. The low permeability characteristic of gas shale plays has spurred the development of new technologies over the years to stimulate production of gas shale reservoirs. Most gas shale wells require stimulation to achieve economic production. A wide variety of different methods and materials have been tested on the Devonian shales of the Appalachian Basin.
What is the current status of shale gas in Canada?Large-scale commercial production of shale gas has not yet been achieved in Canada, but interest has dramatically increased since 2007. Companies have expended over $2 Billion in northeast British Columbia to establish land positions in the Horn River Basin and the Montney trend. With the application of new technologies, many companies are now exploring for potential shale gas deposits not only in Alberta and British Columbia, but also in Saskatchewan, Ontario, Quebec, New Brunswick and Nova Scotia. Recent resource estimates for total gas in place (GIP) of shale gas in Canada: at over 1500 Tcf. (Source: Dawson. 2008.) Figure 4 illustrates the general distribution of shale gas in Canada.
The U.S. experience has shown that each formation will be unique in its characteristics and will present different stimulation challenges. Risk, from an exploration standpoint, is largely in drilling and completion techniques, as these gas shales are typically widespread and continuous. Many companies are expending large amounts of capital to explore for the shale gas resources that lie in these basins. Most of the activity is occurring in the Horn River Basin and the Montney Trend in northeast British Columbia. Early results from the Horn River Basin indicate that the Devonian age Muskwa Formation may be capable of producing significant quantities of natural gas from the predominantly shaley beds. Some early wells have tested at over 5 MMcf/day. Further to the south, the Triassic age Montney Formation has been the focus of many companies for unconventional gas production. Current production is estimated to be greater than 250 Mmcf/day, and many wells are capable of producing greater than 5 MMcf/day initial production rates. Both exploration and development regions have relied heavily on horizontal drilling and multi-stage fracture stimulations to achieve economic well production. Over the next few years, further exploration will focus on the shale resources of the Cordova Embayment (an extension of the Horn River Basin to the northeast) and the lower Montney and Doig shale formations in the Montney trend. In eastern Canada, shale gas exploration activities are reported in the Quebec lowlands, New Brunswick and Nova Soctia. All of these regions are in early days of exploration, and no commercial production has been reported. (Source: Dawson. 2008.) ConclusionGas shales are attracting an increasing amount of attention from Canadian exploration companies, and the trend is expected to increase. The hydrocarbon volume stored within gas shales in Canada is huge. The experience with gas shales in the U.S. has proven the economic viability of the resource. Each basin and sedimentary unit in Canada will have its own unique characteristics and challenges. The low permeability shale gas reservoirs in Canada will require innovative stimulation and completion solutions. Canadian explorers can be expected to rise to the challenge in the very near future. For more information on shale gas, please visit the Centre for Energy website Shale Gas: References and Further Reading
Tight GasWhat is tight gas?The term “tight gas” has not been consistently defined but is generally referred to as the natural gas contained in low permeability sandstone, siltstone and carbonate reservoirs where the application of drilling technology or reservoir stimulation techniques is required to establish economic recovery. Tight gas resources are most similar to conventional gas resources in reservoir lithology and gas storage mechanism. They are commonly distinguished from conventional resources by an arbitrary area and “pay-weighted” in situ permeability cutoff. Other forms of unconventional gas are more easily distinguished from conventional and tight gas storage mechanisms (adsorption and hydrates, for example) and their unconventional reservoir lithology (shale and coal). Where are tight gas reservoirs found?Natural gas stored in both conventional and tight gas reservoirs are primarily stored as a free gas phase in either the lithological matrix or fractures. Gas production commonly occurs by pressure drawdown in the wellbore with subsequent gas expansion and flow from the pores in the rocks through channels and fractures to the wellbore. Tight gas resources occur in reservoir lithologies that preserve or develop porosity and permeability to free gas. Natural gas accumulations tend to be continuous and laterally pervasive and in general, all porosity that is present either in the form of matrix or fractures contains free gas. Areas in these continuous accumulations where gas-bearing rocks exhibit low average reservoir properties have been defined as tight gas. Better reservoir quality zones within these accumulations are commonly referred to as “sweet spots”. Figure 1 illustrates typical tight gas accumulation settings and how “sweet spots” of greater permeability reservoir can reside within regional accumulations.
Where are tight gas reservoirs found in Canada?Tight gas resources can be found wherever the sedimentary rock package happens to be gas-charged. While much of the activity has been focused on the Western Canada Sedimentary Basin, there are other tight gas basins that are either being explored or currently in production in Nova Scotia, New Brunswick, Quebec, Southern Ontario and the Northwest Territories. Figure 2 illustrates the geographical setting of most of the sedimentary basins in Canada that may contain potential tight gas resources.
How is natural gas from tight reservoirs produced?The production of tight gas reservoirs is similar to conventional gas production once the well has been drilled and stimulated. It is in these aspects that the application of technologies has led to a significant resurgence in resource play activities in Canada. In some tight gas reservoirs, the individual gas-bearing rock unit lacks lateral continuity and, as a result, multiple pools of gas may lie in the subsurface but are not connected to each other. In these reservoirs, companies commonly drill multiple vertical or deviated wellbores from a single surface pad location. This type of drilling not only reduces the environmental footprint, but also allows synergies of operations when the wells are drilled and completed. (Figure 3).
Where multiple tight gas reservoirs can be intersected vertically, commonly each zone is stimulated selectively, and then the production from all zones stimulated is commingled. This website has a short animation that illustrates the process of drilling, stimulating and producing multiple zones from a single wellbore. Fracture animation. In tight gas formations that are more laterally pervasive, horizontal drilling allows more of the reservoir rock to be intersected, as well as a greater opportunity to intersect natural fractures that may be present in the reservoir. Horizontal wells can now extend to more than 1500 m into the reservoir, with precision steering of the drill bit to intersect the gas-bearing zones. Figure 4 illustrates a schematic diagram of a typical horizontal well.
In completion technology, the application of large scale fracture stimulations (and the ability to stage these fractures to enable the stimulated interval to be contained within the prospective reservoir horizon) has allowed what used to be considered non-reservoir intervals to reservoir zones that can contribute to the well’s overall production. Staged fracture stimulations segment the horizontal leg of the wellbore into intervals that can then be fracture-stimulated separately. Each stage is segregated from the rest of the horizontal leg to allow the fracture energy to be focused into the stage. The advantage of this process is that the created fracture network is more effective in stimulating a larger volume of reservoir rock. Figure 5 illustrates a typical staged fractured stimulation for a horizontal well configuration.
For more information on natural gas from tight gas sands, please visit: Gas HydratesWhat are Gas Hydrates?Gas hydrates are ice-like substances composed of water and natural gas that form when gases (mainly biogenic methane produced by microbial breakdown of organic matter) combine with water at low temperature and high pressure. Source: Natural Resources Canada An article in the Globe and Mail (May 27, 2005), described gas hydrates as the “world’s greatest untapped source of fossil fuels – and the least understood. Under intense pressure, methane and water molecules combine into a solid mass that is chemically altered, creating “flammable ice.” Those hydrates can range in size from chunks sitting on the sea bed to vast fields underneath the permafrost of the north.”
Why is it important to find out more about gas hydrates?Gas hydrates represent a very large global reservoir of natural gas, and they are estimated to contain more organic carbon than all other known fossil fuel sources combined. They bind immense amounts of methane within sea-floor or Arctic sediments; the breakdown of a unit volume of methane hydrate at a pressure of one atmosphere produces about 160 unit volumes of gas. The worldwide amount of methane in gas hydrates is considered to contain at least 1x104 gigatons of carbon in a very conservative estimate. This is about twice the amount of carbon held in all fossil fuels on earth. Gas hydrates research will lead to a better understanding of the links between gas hydrates and the huge volumes of carbon tied up in them. It will also help us understand its effects, or potential effects on how gas hydrates contribute to climate and climate change. Furthermore, studying the links between gas hydrates and sea floor slope instability will lead to better risk analysis of the potential for underwater land slides and their possible impact on offshore infrastructures and coastal communities. If appropriate recovery technologies are developed, gas hydrates could become a new “clean” energy source and contribute to reducing greenhouse gas emissions worldwide. This would help Canada meet its commitments under the Kyoto Accord. Source: Natural Resources Canada For a description of current studies in Canada on gas hydrates, please visit: Natural Resources Canada Where are gas hydrates found?Gas hydrates exist under large portions of the world's Arctic areas and on deep sea continental slopes in water depths greater than about 600m. All three Canadian continental margins contain gas hydrates. The Mackenzie River delta in the NWT contains some of the most concentrated deposits in the world. A number of other countries such as Russia, the United States, India, Japan and China also have substantial marine gas hydrate deposits. Source: Natural Resources Canada
For more information on gas hydrates, please visit: US Geological Survey map showing where gas hydrates are found For the latest developments in methane hydrate research and development, please visit the US National Energy Technology Laboratory website. |
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