Energy Resources Conservation Board Research Articles

An Analysis of Costs Awarded by the Alberta Energy Regulator

This article assesses the costs regime of the Alberta Energy Regulator (AER) (and its predecessor, the Alberta Energy Resources Conservation Board) since its inception in 1978. An analysis of the policy and legal framework governing the issuance of costs awards by the AER shows that the Board now has a wide scope of discretion in deciding whether to grant costs to a hearing participant, and the process appears less transparent than before. A statistical analysis of the AER's recent costs decisions leads to two conclusions. First, costs awards have overwhelmingly been applied to cover participants’ legal fees, and second, in exercising its discretion to make cost awards, the AER seems more discriminate in its evaluation of certain types of experts.

Drying Behavior of Mature Fine Tailings Pre-Dewatered With Super-Absorbent Polymer (SAP): Column Experiments

Abstract Laboratory column experiments were conducted to investigate the effect of super-absorbent polymer (SAP) on the drying behavior (e.g., dewatering, strength, suction, settlement) of mature fine tailing (MFT). Four experimental columns filled in two different stages with dewatered MFT of 1 wt. % SAP were subjected to atmospheric drying. Moreover, four additional columns (control columns) filled with raw MFT (not pre-dewatered with SAP) were also subjected to drying. The rate of evaporation, drainage, settlement and evolution of suction, strength and void ratio were monitored or determined in a 30-day period. Promising results have been obtained. The results show that the rate of evaporation for SAP pre-dewatered samples was lower than that of raw MFT. Cumulative water lost via evaporation decreased from 13 kg for raw MFT to 7.2 kg for pre-dewatered MFT, which is because of the lower water content of the pre-dewatered MFT. Water drainage for pre-dewatered MFT showed 82 % reduction in comparison with raw MFT within the test period. This finding suggests that the use of SAP pre-dewatered method could considerably reduce the seepage of toxic water from the tailings and MFT impoundments. Developed suction in the first lift showed a sharp reduction by loading the second lift because of redistribution of pore water but this effect was temporary and developed suction in the second lift gained strength. Vane shear strength of pre-dewatered MFT after 30 days was around 3.6 kPa and 7.3 kPa for 5-cm (bottom) and 15-cm heights, respectively, and the strength of the upper parts reached 2.3 MPa. SAP pre-dewatered MFT had a much higher strength increase rate at early ages than the raw MFT. After 10 days of drying, the undrained shear strength at all column heights exceeded or was close to the 1-year value (5 kPa) required by environmental regulations set by the Energy Resources Conservation Board (ERCB). This could have significant practical implication with respect to accelerating the dewatering process and consolidation of MFT, thus increasing the pace of reclamation, reducing the cost of the tailing management and reducing the environmental footprint of heavy oil operations.

Recent Regulatory and Legislative Developments of Interest to Energy Lawyers

This article highlights important legislative and regulatory developments of relevance to energy lawyers, including those involving electricity matters and related jurisprudence that arose between May 2012 and May 2013. The authors have reviewed a wide variety of subject areas, including examining decisions of key regulatory agencies such as the National Energy Board, the Canadian Environmental Assessment Agency, Alberta’s Energy Resources Conservation Board, the Alberta Utilities Commission, the Alberta Surface Rights Board, the Ontario Energy Board, the Ontario Environmental Review Tribunal, and the World Trade Organization. Additionally, federal and provincial legislation and regulations of significance introduced during this period are canvassed.

Investigation of Primary Recovery in Low-Permeability Oil Formations: A Look at the Cardium Formation, Alberta (Canada)

Tight oil formations (permeability < 1 mD) in Western Canada have recently emerged as a reliable resource of light oil supply owing to the use of multifractured horizontal wells. The Cardium formation, which contains 25% of Alberta’s total discovered light oil (according to Alberta Energy Resources Conservation Board), consists of conventional and unconventional (low-permeability or tight) play areas. The conventional play areas have been developed since 1957. Contrarily, the development of unconventional play is a recent event, due to considerably poorer reservoir properties which increases the risk associated with capital investment. This in turn implies the need for a comprehensive and critical study of the area before planning any development strategy.This paper presents performance results from the low permeability portions of the Cardium formation where new horizontal wells have been drilled and stimulated in multiple stages to promote transverse hydraulic fractures. Development of the tight Cardium formation using primary recovery is considered. The production data of these wells was first matched using a black oil simulator. The calibrated model presented was used for performance perditions based on sensitivity studies and investigations that encompassed design factors such as well spacing, fracture properties and operational constraints.

Finding Pathways to Produce Heavy Oil From Canadian Carbonates

Alberta Heavy Oil Nearly 2 million bbl of ultraheavy crude are produced each day from Canadian oil sands, but the notion of also producing bitumen from reservoirs made of carbonate rock can spark skeptical remarks. They are likely to say something like: “Carbonates are very different. In carbonates, it is just different,” said Daniel Yang, director of reservoir engineering at Laricina Energy, who has a different reading of the exploration history of formations that hold more than 400 billion bbl of the crude. Laricina has partnered with a second Calgary independent, Osum Oil Sands, to try to prove that bitumen can be commercially produced from the Grosmont formation, which holds 75% of the heavy crude known as bitumen in Alberta’s carbonates. The reality is the Grosmont is different. A pilot project by Laricina and Osum showed that the well design commonly used for oil sands is not a good fit in carbonates. But a mix of methods used for bitumen production worked well enough to convince the partners to plan a commercial test. that they plan to use for the first commercial development in the formation. The Laricina-Osum joint venture has filed for a permit to produce as much as 10,700 B/D from up to 32 wells, with first oil in 2015. Husky and Shell have also filed for permission to do pilot projects with the Alberta Energy Regulator, the agency formerly known as the Energy Resources Conservation Board (ERCB). “It is going like early development in major oil sands basins such as the Athabasca, where there were many field pilots,” said Eddy Isaacs, chief executive officer of Energy and Environment Solutions at Alberta Innovates, a provincial agency that funds research, including past carbonates work. But moving from wells producing oil in situ in the relatively consistent sandstones and unconsolidated sands to carbonates will require significant advances in production methods and simulation software. The Grosmont was born complicated. It was formed hundreds of millions of years ago from the hap-hazard deposition of marine life off a long shoreline, was chemically transformed into dolomite, followed by water flows that carved it up, widening the fractures and carving out so many holes in the rock that it created weak spots in a formation that has been lifted and crushed and filled with oil that degraded into some of the world’s heaviest crude.

Assessment and Analysis of the Decision of the Alberta Court of Appeal in &lt;i&gt;OMERS Energy v. Alberta (Energy Resources Conservation Board)&lt;/i&gt;

This article provides an assessment of how the findings of the Alberta Court of Appeal in OMERS Energy v. Alberta (Energy Resources Conservation Board) compare and conflict with the approach historically taken by Canadian courts addressing the capability of a well and related issues. The authors then provide an analysis of uncertainties created by the findings of the Court and discuss the implications of the decision for the upstream oil and gas industry.

Production Scheduling and Waste Disposal Planning for Oil Sands Mining Using Goal Programming

In oil sands mining, timely provisions of ore and tailings containment with less environmental footprints are the main drivers of profitability and sustainability. The recent Alberta Energy Resources Conservation Board Directive 074 requires oil sands waste disposal planning to be an integral part of mine planning. This requires the development of a well integrated strategy of directional mining and tailings dyke construction for in-pit and ex-pit tailings storage management. The objectives of this paper are to: 1) determine the order and time of extraction of ore, dyke material and waste that maximizes the net present value; 2) determine the destination of dyke material that minimizes construction cost; and 3) minimize deviations from the production goals of the mining operation. We have developed, implemented, and verified a theoretical optimization framework based on mixed integer linear goal programming (MILGP) to address these objectives. This study presents an integration of mixed integer linear programming and goal programming in solving large scale mine planning optimization problems using clustering and pushback techniques. Application of the MILGP model was presented with an oil sands mining case. The MILGP model generated a smooth and uniform mining schedule that generates value and provides a robust framework for effective waste disposal planning. The results show that mining progresses with an ore to waste ratio of 1:1.5 throughout the mine life, generating an overall net present value of $14,237M. This approach improves the sustainable development of oil sands through better waste management.

Compositions and greenhouse gas emission factors of flared and vented gas in the Western Canadian Sedimentary Basin

A significant obstacle in evaluating mitigation strategies for flaring and venting in the upstream oil and gas industry is the lack of publicly available data on the chemical composition of the gas. This information is required to determine the economic value of the gas, infrastructure and processing requirements, and potential emissions or emissions credits, all of which have significant impact on the economics of such strategies. This paper describes a method for estimating the composition of solution gas being flared and vented at individual facilities, and presents results derived for Alberta, Canada, which sits at the heart of the Western Canadian Sedimentary Basin. Using large amounts of raw data obtained through the Alberta Energy Resources Conservation Board, a relational database was created and specialized queries were developed to link production stream data, raw gas samples, and geography to create production-linked gas composition profiles for approximately half of the currently active facilities. These were used to create composition maps for the entire region, to which the remaining facilities with unknown compositions were geographically linked. The derived data were used to compute a range of solution gas composition profiles and greenhouse gas emission factors, providing new insight into flaring and venting in the region and enabling informed analysis of future management and mitigation strategies. Implications: Accurate and transparent determination of environmental impacts of flaring and venting of gas associated with oil production, and potential benefits of mitigation, is severely hampered by the lack of publicly available gas composition data. In jurisdictions within the Western Canadian Sedimentary Basin, frameworks exist for regulating and trading carbon offset credits but current potential for mitigation is limited by a lack of standardized methods for calculating CO2 equivalent emissions. The composition and emission factor data derived in this paper will be useful to industry, regulators, policy researchers, and entrepreneurs seeking statistically significant and openly available data necessary to manage and mitigate upstream flaring and venting activity and estimate greenhouse gas impacts.

Horseshoe Canyon and Belly River coal measures, south central Alberta: Part 1 -- Total original gas-in-place

Research Article| September 01, 2011 Horseshoe Canyon and Belly River coal measures, south central Alberta: Part 1 — Total original gas-in-place R.M. Bustin; R.M. Bustin Department of Earth and Ocean Sciences, University of British Columbia, 6339 Stores Road, Vancouver, BC V6T 1Z4, bustin@mail.ubc.ca Search for other works by this author on: GSW Google Scholar A.M.M. Bustin A.M.M. Bustin Department of Earth and Ocean Sciences, University of British Columbia, 6339 Stores Road, Vancouver, BC V6T 1Z4, abustin@eos.ubc.ca Search for other works by this author on: GSW Google Scholar Bulletin of Canadian Petroleum Geology (2011) 59 (3): 207–234. https://doi.org/10.2113/gscpgbull.59.3.207 Article history received: 08 Apr 2011 accepted: 13 Sep 2011 first online: 13 Jul 2017 Cite View This Citation Add to Citation Manager Share Icon Share Twitter LinkedIn Tools Icon Tools Get Permissions Search Site Citation R.M. Bustin, A.M.M. Bustin; Horseshoe Canyon and Belly River coal measures, south central Alberta: Part 1 — Total original gas-in-place. Bulletin of Canadian Petroleum Geology 2011;; 59 (3): 207–234. doi: https://doi.org/10.2113/gscpgbull.59.3.207 Download citation file: Ris (Zotero) Refmanager EasyBib Bookends Mendeley Papers EndNote RefWorks BibTex toolbar search Search nav search search input Search input auto suggest search filter All ContentBy SocietyBulletin of Canadian Petroleum Geology Search Advanced Search Abstract Continuously cored Horseshoe Canyon-Belly River (HSC-BR) coal measures in four wells in the middle of the coalbed methane producing fairway in south-central Alberta have been evaluated in order to quantify the total original gas-in-place. Gas contents were determined in all lithologies by a combination of canister desorption experiments and log and laboratory analyses that included adsorption isotherms, measurement of effective matrix porosity to gas, and calculation of fracture porosity and solution gas.The gas-in-place in coals, following the Alberta Energy Resources Conservation Board guidelines (ERCB), only quantifies the desorbed gas, which underestimates the gas-in-place in the coals by 18 to 28%. The balance of the gas occurs as free gas in pores and about 1% to 3% of the gas is calculated to be in solution at reservoir conditions. Inasmuch as the coals are dry (no mobile water), any effective porosity not occupied by adsorbed gas will be occupied by free gas in equilibrium, with the adsorbed and solution gas at the reservoir pressure and temperature. The average effective porosity of most coals ranges from about 4 to 8%, with the duller coals having higher porosity. Gas in fracture porosity, estimated based on measured system permeability and assuming a match stick fracture model, contributes less than 0.4% of the total porosity of the coal seams.With increasing reservoir pressures, there is a proportionally greater amount of gas stored in the free state than the adsorbed state. This is due to flattening of the adsorption isotherm with pressure and thus coal desorption tests result in a greater underestimation of total gas-in-place.Gas also occurs in non-coal lithologies throughout the coal measures. The gas content measured and calculated for each reservoir facies varies primarily because of varying organic content. Canister desorption tests show that adsorbed gas comprises between about 60% and 85% of the total gas-in-place in fine-grained lithologies and that the amount is correlated with organic content (r2 = 0.68). The highest average adsorbed gas contents from desorption experiments occur in the black mudstone (0.42 to 0.52 cc/g; 13.4 to 16.7 scf/ton), followed by the dark grey mudstone (0.23 to 0.32 cc/g; 7.3 to 10.3 scf/ton), siltstone (0.21 to 0.29 cc/g; 6.6 to 9.4 scf/ton) and medium grey mudstone reservoir facies (0.18 to 0.21 c/g; 5.9 to 6.8 scf/ton). The organic matter in most lithologies is particulate carbonaceous material derived from vascular plants (Type III kerogen). Effective porosity to gas in the fine-grained lithologies ranges from about 3.1% to 7.6% and contributes between about 14% to 34% of the total gas-in-place in the coal measures. Solution gas contributes between 1% and 6% to the gas-in-place. Gas storage in the sandstones determined by conventional core analyses indicates effective porosity values ranging from 0.7% to 6.3%, which represents up to 10% of the gas-in-place in the coal measures.Gas in the coal (desorbed plus free and solution gas) represents between approximately 10% and 19% (5.09×107 m3 to 8.34×107 m3/259 ha; 1.8 to 2.95 BCF/section) of the total gas in the coal measures. In the interval from the Upper Horseshoe Canyon coal zone through to and including the Lethbridge coal zone of the Dinosaur Park Formation, the total gas-in-place of the coal measures ranges from 4.32×108 m3 to 4.88×108 m3/259 ha 15.28 to 17.25 BCF/section).Gas contents determined solely by desorption analyses using ERCB guidelines for coal in the HSR-BR results in significant underestimation of the total gas resource, which in turn leads to errors in calculated recovery efficiencies and thus non-optimal well spacing and development strategies. 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An Analysis of Flaring and Venting Activity in the Alberta Upstream Oil and Gas Industry

ABSTRACT Alberta, Canada, is an important global producer of petroleum resources. In association with this production, large amounts of gas (1.14 billion m3 in 2008) are flared or vented. Although the amount of flaring and venting has been measurably reduced since 2002, data from 2005 reveal sharp increases in venting, which have important implications in terms of resource conservation and greenhouse gas emissions (which exceeded 8 million tonnes of carbon dioxide equivalent in 2008). With use of extensive monthly production data for 18,203 active batteries spanning the years 2002–2008 obtained in close cooperation with the Alberta Energy Resources Conservation Board, a detailed analysis has been completed to examine activity patterns of flaring and venting and reasons behind these trends in the Alberta upstream oil and gas industry. In any given year, ∼6000 batteries reported flaring and/or venting, but the distribution of volumes flared and vented at individual sites was highly skewed, such that small numbers of sites handled large fractions of the total gas flaring and venting in the Province. Examination of month-to-month volume variability at individual sites, cast in terms of a nominal turndown ratio that would be required for a compressor to capture that gas and direct it into a pipeline, further revealed that volumes at a majority of sites were reasonably stable and there was no evidence that larger or more stable sites had been preferentially reduced, leaving potential barriers to future mitigation. Through linking of geospatial data with production data coupled with additional statistical analysis, the 31.2% increase in venting volumes since 2005 was revealed to be predominantly associated with increased production of heavier oils and bitumen in the Lloydminster region of the Province. Overall, the data suggest that quite significant reductions in flaring and venting could be realized by seeking mitigation solutions for only the largest batteries in the Province. IMPLICATIONS Global flaring and venting of substantial volumes of waste flammable gases is a significant environmental concern. Alberta, Canada, is an example of a jurisdiction that has achieved significant reductions in flare and vent volumes from historic highs; however, these efforts have stalled in recent years. Through unprecedented access to several years of site-by-site production data for the entire upstream oil and gas industry in this region, a detailed analysis of current practices and activity trends in flaring and venting in Alberta has been made possible for the first time. The results of this analysis, including a specific investigation of potential barriers to mitigation of flaring and venting in a mature oil- and gas-producing region, have important implications for flaring and venting mitigation throughout the world.

Recent Regulatory and Legislative Developments of Interest to Energy Lawyers

This article identifies recent regulatory and legislative developments of interest to oil and gas lawyers. The authors survey a variety of subject areas, examining decisions of key regulatory agencies such as the National Energy Board, the Ontario Energy Board, the Alberta Energy Resources Conservation Board, the Alberta Surface Rights Board, and the Alberta Utilities Commission, as well as related court decisions. In addition, the authors review a variety of key policy and legislative changes from the federal and provincial levels.

Use of a Plume-Modeling Study To Reduce the Risk of H2S Release in an Exploration Well

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper IPTC 13636, ’The Use of a Plume Modelling Study to Reduce the Risk of H2S Release in an Exploration Well to as Low as Reasonably Practicable (ALARP),’ by J.G. Mcllroy, SPE, Petroleum Development Oman, originally prepared for the 2009 International Petroleum Technology Conference, Doha, Qatar, 7-9 December. With the increasing likelihood of exploration wells being near population centers, a blueprint for the evaluation of the risk of an uncontrolled release of gas reaching such a settlement needs to be quantified. The full-length paper reviews a case study from Oman in which a plume-(gas cloud) modeling study was completed to determine the level of hydrogen sulfide (H2S) away from an exploration well. Introduction Within Petroleum Development Oman’s (PDO’s) Block 6 license, the South Oman salt basin has been widely explored. The discovery of oil-bearing carbonates encased in salt (referred to as “stringers”) led to deeper drilling and more-challenging technical issues, including increasing pressures and the presence of H2S. The well under consideration was notable as the first stringer well to be close to a significant population center. The full-length paper includes background information, key study elements, results, and identified risk-mitigation actions required to reduce the risk to as low as reasonably practicable (ALARP). Modeling PDO has been involved in drilling operations in onshore Oman for more than 40 years and has a very high success rate in terms of wells drilled safely. This overpressure stringer well represents another well drilled to a target within the salt, and as such is “business as usual” from an exploration perspective, but the presence of the nearby settlement requires a more-complete approach to risk analysis. This called for modeling of physical effects (toxic dispersion) of an unconstrained flow from a well. The blowout frequency and probability of blowout type are based on reviews of reports compiled for previous clients. This led to a review of the existing PDO operational Bow-Tie (or risk and outcome) analysis to assess the adequacy of controls (existing and planned) to reduce risk to tolerable and ALARP. The following key steps were followed in this study. An assessment of the likelihood of an uncontrolled H2S release (blowout) occurring. This was based on available global statistics. Computer modeling of near- and far-field H2S concentrations that would result from several release scenarios, which used software from the Energy Resources Conservation Board (ERCB) of Calgary, Canada, and software developed by Shell (for consequence and risk modeling). The Shell dispersion-modeling results were considered more appropriate for the relatively near-field-concentration calculations. It provided more input control than the ERCB software because it allowed entering a large number of parameters including process conditions. This also includes the estimates of the probabilities of the blowout types (with drillpipe and without drillpipe) and the estimate of fluid type.

Prospects for Commercial Bitumen Recovery from the Grosmont Carbonate, Alberta

Abstract The last few years have seen the end of the Athabasca land play and the revival of interest in Alberta's bitumen resources in carbonate reservoirs. Of these, the Grosmont Formation is the most promising in terms of resource size and concentration. It is also the best known, in terms of having been the subject of several in situ pilots operated in the late '70s and early '80s. The data recorded from these early pilots is priceless in terms of having a touchstone of reality for new process concepts. On the other hand, the interpretations written in those days ('before gravity') are not necessarily as helpful. This paper looks at the Grosmont in terms of facts and fundamentals, and presents the case for Grosmont exploitation. There is good evidence that the Grosmont has very high bulk permeability as a result of karst porosity development and fracturing. This bodes well for the use of modern gravity drainage methods in the Grosmont. Introduction Grosmont Piloting History The Grosmont Formation in north-central Alberta is a dolomitized, karsted and fractured platform carbonate containing a massive bitumen accumulation. An excellent historical summary of various Grosmont pilots was recently provided by Alvarez et al.(1) Cyclic Steam Stimulation (CSS), steam drive and forward combustion were all attempted in the Grosmont during the '70s and '80s. CSS was the most widely and successfully piloted method. The best well, at 10A-5-88-19W4, recovered about 100,000 bbls of oil over 10 cycles, with a cumulative steam-oil ratio (CSOR) of about 6. Results of other tests were mixed, as were the operating procedures; most of these were based on horizontal flooding concepts. However, responses to well-executed CSS first cycles were reasonably similar at a number of widely-spaced wells. Notably, steam injectivity was generally sufficient so that a few hundred tonnes/day could be injected at pressures that were significantly below overburden pressure (ruling out geomechanical enhancement of permeability). A degree of pessimism, or at least great caution, has been expressed with respect to the supposed complexity of the reservoir, and hence, prospects for commercial recovery. In particular, it is often said that the reservoir is very heterogenous, and that this explains the historical failure of attempted steam drive and fire flood processes. Review of the Unocal Buffalo Creek and McLean scheme reports(2, 3) suggest that much of this originates in the interpretations of the contemporary operators, who largely explored conventional EOR concepts involving horizontal displacement. They expected to recover oil by means of horizontal, radial flow. When this failed, it was natural to assume that the problem lay in a failure to maintain the 'radial' part of the prescription, due to permeability heterogeneity. Figure 1 presents the performance of the Buffalo Creek 10A-5 CSS test in perspective with a contemporary test and two modern-day, commercially-optimized CSS wells (the data is publicly available from the Alberta Energy Resources Conservation Board). It can be seen that the Grosmont well had comparable performance to a Clearwater CSS test of the same vintage.

Recent Regulatory and Legislative Developments of Interest to Oil and Gas Lawyers, 2007 &amp;mdash; 2008

This article highlights regulatory and legislative developments during the period of May 2007 through April 2008 that are of interest to oil and gas lawyers. The article primarily examines decisions and other related jurisprudence of the National Energy Board and the Alberta Energy and Utilities Board, the latter of which was split into the Energy Resources Conservation Board and the Alberta Utilities Commission on 1 January 2008. Additionally, the article details policy and legislative developments affecting the National Energy Board and the two new Alberta regulators. Regulatory developments at the Alberta Surface Rights Board and in other jurisdictions are also considered.

Evaluation of the Potential for Gas and CO2 Leakage Along Wellbores

Summary Implementation of carbon dioxide (CO2) storage in geological media requires a proper assessment of the risk of CO2 leakage from storage sites. Leakage pathways may exist through and along wellbores, which may penetrate or be near to the storage site. One method of assessing the potential for CO2 leakage through wells is by mining databases that usually reside with regulatory agencies. These agencies collect data concerning wellbore construction, oil and gas production, and other regulated issues for existing wells. The Alberta Energy Resources Conservation Board (ERCB), the regulatory agency in Alberta, Canada, collects and stores information about more than 315,000 oil, gas, and injection wells in the province of Alberta. The ERCB also records well leakage at the surface as surface-casing-vent flow (SCVF) through wellbore annuli and gas migration (GM) outside casing, as reported by the industry. The evaluation of a leakage pathway through wellbore casing or annuli and what causes these wellbore leaks are the first step in determining what factors may contribute to wellbore leakage from CO2-storage sites. By using available data, major factors that contribute to wellbore leakage were identified. Data analysis shows that there is a correlation between these SCVF/GM and economic activity, technology changes, geographic location, and regulatory changes regarding well completion and abandonment. Further analysis indicates a relationship between low-annular-cement top, external corrosion, casing failure, and wellbore leakage (SCVF/GM). Other factors that could affect the presence of wellbore leakage, such as wellbore deviation, surface-casing depth, and wellbore density, were also investigated. This paper presents the findings of the data analysis and a method to evaluate the potential for leakage along wells in an area where CO2 storage is intended. This information is useful not only for future operations of CO2 storage in geological media, but also for current operations relating to the exploration and production of hydrocarbons.

Incorporating Low Frequency Noise Legislation for the Energy Industry in Alberta, Canada

Environmental noise from energy industry facilities in Alberta, Canada, is regulated by the province's Energy Resources Conservation Board (ERCB) (until 2008 known as the Alberta Energy and Utilities Board [EUB]) as set out in Directive 038: Noise Control. The 2007 edition of the directive, which comprises a comprehensive policy and guide, adopts A-weighted energy equivalent sound levels (LAeq), with sound pressure level criteria, as the primary measurement system for a receptor location. With the receptor being some distance from the energy industry noise source, the high and medium frequency components can dissipate or be absorbed by air and ground conditions, leaving mostly low frequency noise (LFN). Consequently, A-weighted measurements do not reflect the full annoyance potential of the remaining industrial noise. Complaints related to LFN are often described by the affected party as a deep, heavy sound, like “humming”, sometimes with an accompanying vibration. In some cases, the direction of the source of the LFN will be unknown to the receptor. However, it is the complainant that is most able to detect the presence of the LFN, signifying a particular sensitivity of the individual to the sound while others in the same family may not be able to detect the sound at all. To make a proper determination for the presence of LFN, the data must be collected during a time when environmental conditions are representative of when the sound is annoying. Residents who are impacted by LFN may suffer from sleep disturbances, headaches, and in some cases chronic fatigue. This paper examines the work undertaken by the ERCB to understand the issue, the various metrics tested to easily identify LFN, and finally the approach that would be incorporated into the new 2007 edition of Directive 038: Noise Control to address the problem.

カナダオイルサンドの開発〜さらなる挑戦

Bitumen from oilsands that has been regarded only as an alternative resource for the next generation in Japan is recognized as what makes up production decline of conventional petroleum resources at the North American crude oil market. One third or more of the total oil production in Canada is from synthetic crude oil based on the bitumen or the diluted bitumen. Therefore, the bitumen has already shown its presence and will no longer be called unconventional.The order of Canadian oilsand in-place is equal to that of Saudi Arabia's. The Energy Resources Conservation Board (ERCB) estimated that Athabasca area has 1, 600 billion bbls of bitumen in-place and it has been regarded as one of the largest hydrocarbon reserves in the world. The amount of reserves is formally evaluated as 175 billion bbls by ERCB and the Alberta Energy Utilities Board (AEUB) at present.Major oil companies are positively involved in the Canadian oilsand development as oil business, positioning it as one of the important investment options for making balance against the investment risks in geopolitically unstable areas, so that it is included in their global portfolios from a viewpoint of stable oil supply. There is a prediction that the bitumen production will reach two thirds of the oil production in Canada within a decade and will also increase three times by 2017.The huge amount of the bitumen reserves will fill the gap between supply and demand of the North American oil market. Athabasca may become one of the main production centers and the oilsand bitumen may be in a global portfolio of oil companies as a long-life and stable resource. Solutions to problems such as total process establishment, stabilization of netback bitumen price and gas price, and expansion of the market are breakthrough points to make the story much more realistic.

Energy Regulation and the Role of the Market

This article focuses on the changes and effects of tribunal policies and decisions on industry players since the deregulation of the oil and gas industry. Specifically, it addresses the manner in which the National Energy Board and the Alberta Energy ("NEB") and Utilities Board ("EUB") (formerly the Energy Resources Conservation Board) have cultivated a forum that fosters free market competition. In particular, the Boards articulate position of minimal interference in commercial decisions unless public interest or environmental well-being are placed at risk. Specific examples of applications for the construction of new pipelines and resulting NEB decisions and reasons are further highlighted in this article. In addition, the article looks at similar EUB positions regarding pipeline proliferation projects. Overall, the article juxtaposes the need to facilitate energy customers, distributors and producers in achieving fair market prices with the need for tribunal intervention in balancing such transactions with public interest concerns.

Canadian forest service's participation in check sample programs over a 25‐year period

To ensure that a laboratory produces credible analytical results, it is important to participate in collaborative studies utilizing check samples as a method of implementing a quality control procedure. This paper describes the following twelve check sample programs in which the Canadian Forest Service has participated during a 25‐year period to ensure that it produces high quality analytical results: Acid Rain Direct/ Delayed Response Project, Alberta Institute of Pedology, AOAC INTERNATIONAL, Canada Soil Survey Committee, Energy Resources Conservation Board, Expert Committee on Soil Survey, International Soil‐analytical Exchange, International Union of Forestry Research Organizations, Laboratory Exchange, Long Range Transport of Air Pollutants, Utah State University, and Western Enviro‐Agricultural Laboratory Association.

Options for Small-Scale Sulfur Recovery

Summary With the issuance by the Alberta Energy Resources Conservation Board and Alberta Environment of their report entitled Sulphur Recovery Guidelines for Sour Gas Plants in Alberta in August of 1988, the requirement in Alberta to recover sulfur was broadened to a sulfur content of 1 tonne/D or greater in the inlet gas to a new sour-gas treating plant. This paper reviews the processes in use for recovering sulfur from sour-natural-gas streams that have a total sulfur content of 5 tonne/D or less. These processes are the modified Claus process, the recycle Selectox process, and the reduction/oxidation processes LO-CAT and SulFerox. While the modified Claus process is used in large sulfur-recovery plants, the other processes may be more economical for sulfur recovery on a small scale. A description of the sour-gas treating and sulfur-recovery processes is given, and a comparison of estimated capital and operating costs for typical sour-gas streams is provided. All of the above processes are in operation in North America. Operating experiences with these processes in Alberta are discussed. The quality of the end-product sulfur varies among these processes, and the options for sulfur disposal are reviewed.