Alberta Gas Research Articles

Slant rigs offer big payoffs in shallow drilling : Smith, J; Edwards, B Oil Gas JV90, N13, 30 March 1992, P64–66

Slant hole drilling technology can result in considerable savings over conventionally drilled deviated holes because mud motors and deviation control with measurement while drilling tools are usually unnecessary. The benefits of using slant hole rigs for development drilling improve after the bit walk tendencies and the correct bottom hole assemblies have been determined for a particular area. This article discusses three recent drilling operations that successfully used slant drilling technology on land-based projects: drilling for heavy oil in Alberta, drilling for gas in Alberta, and drilling a river crossing for a gas pipeline in British Columbia. These examples demonstrate the flexibility of slant drilling technology.

Alberta Gas in United States Markets: Canadian and American Perspectives on Competition, Constitutional and Contract Enforcement Issues

The authors discuss regulatory issues of particular importance and topicality. Included are considerations of the question of whether the pricing pool arrangements under the Alberta Natural Gas Marketing Act, as amended in 1991, may be challenged as violations of the Competition Act (Canada) or the Sherman Antitrust Act (United States) or the Free Trade Agreement between Canada and the United States. The constitutional validity of the amended Alberta Natural Gas Marketing Act is reviewed. The effects of decisions of state regulatory tribunals on contracts for purchase and sale of natural gas are examined in the context of the United States Constitution.

A comparison of alumina, carbon and carbon-covered alumina as supports for NiMoF additives: gas oil hydroprocessing studies

Catalysts with 3 wt% NiO, 15 wt% MoO 3 and 0–6.9 nominal wt% fluoride supported on alumina, carbon and carbon-covered alumina were studied to examine the role of fluoride and the influence of the support on hydroprocessing on Alberta gas oil. Experiments were carried out in a batch reactor at 410 °C and 6.9 MPa initial H 2 pressure. It was found that fluoride promotion enhances cracking and hydrogenation reactions resulting in decreased aromatic and sulphur contents in the gas oil. The promotion is dependent on the type of support and is related to the strength of the fluoride-support interaction and the accessibility of the fluoride to the surface hydroxyl groups on the support. A maximum in activity at 3.6 wt% fluoride was observed for the alumina-supported catalysts whereas higher loadings of fluoride were required for carbon-covered alumina-supported catalysts to see an improvement over their carbon supported counterparts. However, the carbon-covered alumina supported catalysts seem to have a lower propensity for coke deposition than their alumina counterparts.

Well Testing In Alberta — 1990s Style

Abstract This paper presents the highlights of a new guide for well pressure and deliverability testing in Alberta. The guide was developed by a joint Industry-ERCB committee to reduce test costs, improve test quality, and clarify testing regulations. New requirements define quality pressure survey methods, and the minimum number of tests that should be run for prudent reservoir management. Relief from testing is provided for advanced depletion, small reserves, low permeability, heavy oil, low productivity, and reduced spacing. In addition, testing costs are reduced by accepting pressures from shut-in wells, acoustic methods, and drill-stem tests, under certain conditions. Operators can choose the type of deliverability test they run: single- vs multi-point. Tests can be scheduled to optimize field operations. The new well testing environment for the 1990s should become less regulated but this requires that the operating industry be committed to quality testing in accordance with the new guide. The industry, the ERCB, and the public stand to gain from this new approach to data gathering. Introduction In 1989, it cost over $250 million dollars to run pressure and deliverability tests for Alberta's oil and gas wells. This cost is expected to increase significantly, throughout the 1990s, as more wells are needed to supply existing and new markets for oil and gas. The time has come to ensure that we get the most from future testing dollars by carefully examining our data needs and test procedures. The Energy Resources Conservation Board (ERCB) has a mandate(1) to provide for the gathering and dissemination of information regarding the energy resources of Alberta. Accordingly, it developed regulations(2), as early as 1961, for the taking and reporting of well tests. The purpose of these regulations is to ensure adequate quality pressure and deliverability data, for use in engineering and economic studies of Alberta's oil and gas pools. Over the years, these regulations were revised a number of times in response to the changing needs of the ERCB, and the operating industry. In 1987, a joint Industry-ERCB technical committee (the committee) was formed to review the ERCB's well testing regulations. The review has resulted in the development of a new guide for well testing(3). A draft of the new guide was distributed to several industry associations: IPAC, CPA, SEPAC, and CIM, for their comments. Their responses suggest that the guide was well received but that further effort is needed to clarify its contents. The ERCB decided to release a first edition of the guide in the second quarter of 1990. This was done to give both the ERCB and the industry an opportunity to work with the revised requirements, and benefit from them without delay. The ERCB has asked the committee for a review of well testing under the new guide in mid-1991. Any problems encountered can be addressed in a second edition of the guide. Assuming no major problems remain, the ERCB will formally adopt the second edition or the guide as part of its regulations.

Projection of Carbon Dioxide Emissions from Natural Gas Combustion and Steam-Reforming of Methane in Alberta

Anthropogenic emissions of carbon dioxide into the atmosphere come primarily from the combustion of fossil fuels and deforestation. Concentrations of carbon dioxide, along with other greenhouse gases, are expected to exacerbate the climate wanning trend and lead to a number of changes in the terrestrial biosphere. The purpose of this paper is to identify and project the sources of carbon dioxide emissions from combustion and conversion of natural gas in Alberta.

Measuring resource scarcity in non-renewable resource with an application to oil and natural gas in Alberta

In this paper annual Canadian exploration data are used to estimate a multiple-output translog exploration cost function. A new definition of depletion is introduced and its estimated coefficient is found to be statistically significant. The fitted cost function parameters are then used to obtain estimates of the marginal costs of exploration for oil and gas. Our estimated marginal exploration costs are smaller than in previour studies because we have allowed for technical progress which offsets the depletion effects. These marginal cost estimates are employed, along with previous estimates of exploration rents, to measure resource scarcity. We find some evidence for the increased scarcity of oil and gas in Alberta. For oil there is a 10.1% per year increase in scarcity along the trend line while for natural gas there is a 2.4% per year increase in scarcity along the trend line.

Alberta's Small Gas Pool Reserves

Abstract Small, single-well pools presently contain about 28% of Alberta's remaining marketable gas and their share is steadily increasing. A performance study was conducted for 2668 small gas pools producing from a variety of geological zones throughout the province. Reserves from performance are 25% lower than initial volumetric reserves. Much of the difference is attributed to depleted pools and pools where water has curtailed gas production. The pools studied are grouped into 29 zones to examine results and to compare with small shut-in pools. Also included are revised productive areas that the ERCB has adopted for estimating small gas pool reserves. Introduction A decreasing trend in the size of gas pool discoveries is well established in Alberta(l). As large pools become more depleted, small pools will be called upon to replace increasing volumes of reserves and production. What is a small pool? There is no completely satisfactory definition because estimates of a pool's size or reserves can change over time. In this paper, a small pool is defined as a non-associated, single-well pool; therefore, the terms "pool" and "well" are used interchangeably. Presently, some 15 000 (71%) of Alberta's gas pools are in this category, and together they contain about 435 billion m3 (28%) of the province's remaining marketable gas. With the oversupply of gas in Alberta, most small gas pools remain shut in. Between late 1985 and early 1987, the Energy Resources Conservation Board (ERCB) reviewed manually the performance of 2668 small pools that had produced. The initial volumetric reserves based on a nominal 200-hectare area were found to be overstated by about 25%. While performance methods can sometimes be misleading, most of the net reserve reduction is accounted for in depleted or watered-out pools. These findings raisedsome important questions about the large inventory of reserves booked in small shut-in pools. Following its review, the ERCB revised the productive areas it assigns to single-well pools in certain Cretaceous zones, The.se revisions have dropped reserves in small shut-in pools about 11%. Further adjustments may be necessary if the early indications for some zones are confirmed by additional performance monitoring. Historical Development The total number of small gas pools in Alberta (Fig. 1) climbed rapidly after 1975 in response to increased gas prices. Other factors that may have contributed to this growth were several large area-purchase contracts issued by major buyers; tough surplus tests(2.3); and resource basin maturity. Most (12 000) of these small pools have never produced because of the slow growth in gas markets(4), However, the annual production from small pools has increased nearly five fold since 1975 (Fig, 2). In 1987, small pools contributed about 8 billion m3 (l2%) of Alberla's total marketed gas production. To support the growth in annual production, over 200 new small pools were tied in each year (Fig. 3). The average initial rate of a new well is 44 000 m3 per day. When the ERCB began its study (late 1985), the pools reviewed had an average produced life of four years.

Geologic, Logistic, and Economic Controls on Current Shallow Gas Production in Southwestern Saskatchewan: ABSTRACT

Biogenic shallow gas is commercially produced from three Upper Cretaceous lithostratigraphic units in southwestern Saskatchewan: the second white-speckled shale, the Medicine Hat Sandstone, and the Milk River Formation. Major geologic characteristics of each of these units in the study area compare laterally with equivalent gas-producing strata in southeast Alberta (southeast Alberta Gas System) and north-central Montana (East Keith, Tiger Ridge-Bowes-Bull Hook, and Bowdoin fields). Exploration for and, more particularly, development of shallow gas pools in southwestern Saskatchewan have greatly increased since 1982 (average number of gas wells per annum from 1960 to 1982 inclusive was 47, and from 1983 to 1987 inclusive was 460), despite a sharp decline in 1986. Logistic and economic factors influencing this pattern include current project-development methods and costs in this highly active gas play.

Structural analysis of Alberta heavy gas oils

A Structural Group Analysis (SGA) technique was developed for characterization of Alberta gas oils. The gas oils were separated into class fractions enriched in selected structural groups. Data from elemental analysis, 1H n.m.r., 13C n.m.r. and i.r. spectroscopy were used in an optimization procedure to obtain the group concentrations. Stuctural profiles are presented for four gas oils which give a description of the amounts of aromatics, hydrogenated rings, alkyl structures and heteroatomic groups. The accuracy of the method was tested on calibration mixtures and the predicted concentrations of most aliphatic groups were within ±20% of known concentrations. Reproducibility of the method was also tested by a repeat analysis of one gas oil. Variations in group concentrations were within the expected error of ±20%.

Natural Gas Deregulation: Review and Perspective

This paper presents a review of the development of the statutory framework for implementing natural gas regulation in Canada and the steps in the process of "deregulation "followed by a discussion of some of the major outstanding issues arising directly from the process of deregulation. Some of the issues discussed in the context of deregulation include the federal and Alberta surplus tests, the pressure on existing long term gas contracts being exerted by consumer provinces, the bypass option and Alberta gas removal permit procedures.

Marketing of Alberta Gas for Export under Deregulation

This paper examines the current regulatory framework respecting the export of AIberta natural gas to United States markets. It contains an outline of the current Canadian and certain American regulatory requirements to be fulfilled, discusses producer concerns respecting some effects of certain of these requirements and briefly raises certain practical concerns respecting available pipeline capacity required to transport natural gas from Alberta to the United States.

Design Considerations For Carbon Dioxide Injection Facilities

Abstract The first miscible carbon dioxide enhanced oil recovery project in Canada began in 1984 with the injection of CO2 into the Joffre Viking Tertiary Oil Unit by Vikor Resources Ltd. and the Alberta Oil Sands Technology and Research Authority (AOSTRA). Carbon dioxide injection facilities capable of injecting gaseous CO2 from a nearby petrochemical complex and liquid CO2 trucked to the site are discussed. The paper examines some process, instrumentation, material and operating considerations incorporated into the design of the project's carbon dioxide compression, dehydration, injection well and measurement equipment. Introduction Since the early 1970s considerable effort has been expended by industry in the research and field testing of miscible displacement of oil using CO2. In the United States, the number of CO2 miscible projects have blossomed to over thirty in the past two years. In the United States carbon dioxide miscible flooding is expected to contribute about 50 000 m3 I d of tertiary oil by 1995, and should develop dose to 500 million m3 of oil reserves. Although the potential a f miscible CO2 flooding is somewhat more limited in Canada than in the United States due to the lack of large natural occuring CO2 deposits, miscible CO2 flooding is still expected to contribute significantly to Canada's future oil reserves. A recent study by the National Energy Board (NEB) showed carbon dioxide miscible flooding to have an economic potential for recovering 50 million m3 of oil reserves, about 15% of Canada's anticipated 320 million m3 tertiary oil reserves. The first field testing of miscible CO2 technology in Canada is currently being operated by Vikor Resources Ltd. on behalf of the Alberta Oil Sands Technology and Research Authority (AOSTRA) and the Joffre Viking Tertiary Oil Unit in the Joffre Viking sandstone, approximately IS km northeast of Red Deer (Fig. 1). The project is located in an area of the reservoir which had been produced to its economic limit under water flood in the 1960s. The project consists of four water pre-pressure wells flanking two adjacent inverted five-spot CO2 injection patterns which are produced under a water alternating gas (WAG) process (Figs. 2 and 3). The project has been injecting CO2 since January 1984. Response to the CO2 injection has been observed, indicating the commercial potential of the process. This paper will deal with some of the process and mechanical design considerations of the CO2 injection system in Joffre; identifying potential problems specific to CO2 and commenting on recommendations to economically ameliorate each problem area. Injection System The CO2 injection system is shown schematically in Figure 4, It includes gaseous CO2 from Alberta Gas Ethylene Company (AGEC) and a liquid CO2 system located at the Central Battery. These two CO2 sources are comminglid at the Vikor Central Battery, and then distributed to the WAG injection wells. Separate water and CO2 injection systems to each WAG injection well are provided as corrosion in gaseous CO2 streams depends mainly on the presence of water.

Pricing Alberta's Gas - Cooperative Federalism and the Resource Amendment

After discussing the “resource amendment” to the constitution (92A) and reviewing the statutory framework in the energy sector, the author goes on to look at the constitutional implications of the dual Federal-Alberta pricing structure, which involves a considerable overlap of jurisdiction.

Water Use at Alberta Gas Ethylene

Alberta Gas Ethylene Co. Ltd. (AGEC), a subsidiary of NOVA AN ALBERTA CORPORATION, operates a world-scale petrochemical plant at Joffre, Alberta, 20 km east of Red Deer. This plant withdraws an average of about 2500 dam3 of water per year from the Red Deer River, mainly for cooling purposes. Approximately 70 percent of this is consumed, mainly through evaporation and drift from the cooling tower. Waste water is discharged to the River on a batch basis after treatment.The consumption of Red Deer River water by Alberta Gas Ethylene averages about 0.06 m3/s, with a maximum monthly rate of 0.10 m3/s. Dickson Dam is to guarantee a minimum flow of about 16 m3/s in this area of petrochemical development. It is estimated that the maximum consumption of water from the Red Deer River by all petrochemical users will not exceed one m3/s in the year 2000. Other withdrawals from the river may total close to 10 m3/s, over half of which would be consumed. Alberta Government decisions regarding the amount of Red Deer River water that will be allocated to Saskatchewan could restrict further consumption in the basin shortly after the turn of the century.Alberta Gas Ethylene has engaged in several efforts to recycle water. It is estimated that water withdrawals have been reduced by as much as 20 percent, and wastewater discharges by 70 percent. Operational costs have thereby been reduced and the impact of the plant on the environment has been lowered. AGEC has shown that sewage and process wastewaters can be used as cooling water make-up without adversely affecting cooling tower operation. The net consumption of water from the Red Deer River has not, however, been affected.

Canadian PVC producers looking to exports

When Esso Chemical Canada comes on stream—probably next month—with its 50,000 metric-ton-per-year addition to its polyvinyl chloride (PVC) plant at Sarnia, Ont., it will increase total Canadian PVC capacity 17% to 346,000 metric tons annually. More important, it will raise capacity even further above demand in Canada, which is expected to run about 200,000 metric tons this year. This, in turn, will make it even more important for Canadian PVC producers to secure export markets for their products. The burden to do this will fall especially heavily on Diamond Shamrock Alberta Gas (DSAG), the sole Canadian PVC producer in western Canada. DSAG is owned jointly by Diamond Shamrock and Nova, an Alberta Corp. Nova also owns Alberta Gas Chemicals, but operating responsibility for the DSAG PVC plant has been given to Novacor Chemicals, another Nova subsidiary formed to direct, control, and eventually own Nova's petrochemical interests. DSAG has a 100,000 metric-ton PVC plant at ...

Significance of Gamma-Ray Spectroscopy for Evaluating Shallow Gas Reservoirs from Bowdoin Dome, Montana: ABSTRACT

Natural gas is currently being produced from shallow gas reservoirs of Late Cretaceous age in the Bowdoin dome area, north-central Montana. Clay-rich rocks of the Mosby Sandstone Member of the Belle Fourche Shale, the Greenhorn Formation, and the Carlile Shale are the principal reservoirs. Laterally equivalent rocks are major producers of gas in southeastern Alberta. The Mosby consists of composite bedsets of lenticular to wavy-bedded sandstone and dark-gray shale. The Greenhorn, which unconformably overlies the Mosby, is as much as 40 ft (12 m) thick and consists of black, organic carbon-rich (as much as 9% organic carbon) shales, bentonites, and calcarenties consisting mainly of inoceramid prisms. Lateral equivalents of the Greenhorn are probably the principal source be s for oil occurrences farther west in the Montana disturbed belt. The Carlile Shale overlies the Greenhorn with apparent conformity and is lithologically similar to the Mosby. However, the Carlile mudstones contain more smectitic mixed-layer clays than those of the Mosby. Exploration and production of hydrocarbons from these clay-rich rocks present significant problems in log interpretation and in well completion and treatment procedures. In an effort to address these problems, a detailed geochemical, petrologic, mineralogical, and stratigraphic study was undertaken to characterize the gas-productive formations at Bowdoin dome and to evaluate the usefulness of natural gamma-ray spectroscopy for interpreting geology and reservoir quality. The gamma-ray spectral log resolves the total gamma-ray spectrum into the three most common components of radiation--gamma rays from 40K, U-series decay, and Th-series decay. In principle, the log can be used to determine clay content, clay composition, source-bed richness, and lithology. Results of this inv stigation suggest that the log successfully estimated organic-carbon content, identified bentonites, and located the unconformity at the base of the Greenhorn. In addition, subtle differences in clay composition between the Belle Fourche and Carlile Shales were apparent. These differences in clay mineralogy have important implications for interpreting the irreducible water saturation and water sensitivity of the formations and thus for the choice of drilling and completion techniques. Detailed analyses of individual core samples provide much more accurate information about single point samples than did interpretations of single points from the spectral log. However, analyses of individual core samples only distinguish mineralogical or geochemical deviations with frequencies greater than two times the sampling interval. In contrast, the log provided a running average capable of resolving relatively small-scale fluctuations and displayed considerable precision and accuracy when calibrated to laboratory analyses. In conclusion, gamma-ray spectroscopy provides a potentially important tool for the investigation of unconventional gas reservoirs and source beds in clay-rich and organic carbon-rich rocks. End_of_Article - Last_Page 468------------

Canadian methanol enters alternate fuel market

Celanese Canada, with its huge 700,000 metric-ton-per-year methanol plant at Edmonton, Alta., nearing completion, has decided to enter methanol in the Canadian alternate fuel sweepstakes. Methanol will have to compete against several other contenders, including compressed natural gas and propane. Just how big a role, if any, methanol will play in the Canadian transportation fuel market still is unclear. But Celanese Canada is confident that, of them all, methanol is the one fuel that is capable of having the most significant impact. At a recent meeting of the Chemical Institute of Canada, Neil Martin, vice president of Celanese Canada's chemicals and industrial products group, explained why. One big factor in methanol's favor, Martin says, is availability. Canadian methanol capacity is about to take a quantum leap. Alberta Gas Chemical already has doubled its methanol capacity at Medicine Hat, Alta., from 360,000 metric tons to 720,000 metric tons annually. And, in addition to the Celanese world-scale ...

Hydrocarbon Accumulations in Overthrust Belt of Alberta: ABSTRACT

Estimated proved and probable ultimate reserves of marketable natural gas in Alberta are 80.5 tcf, of which approximately 10.5 tcf are in Paleozoic carbonate reservoirs that have been involved in thrust faulting in the Foothills belt of Alberta. Interpretation of exploration data in this belt has contributed significantly to our understanding of the geology of the southern Canadian Rocky Mountains as a whole. The Precambrian basement is overlain by a westward-thickening prism of Paleozoic sedimentary deposits that contain important reservoirs in Upper Devonian and Mississippian carbonate rocks. Approximately 8% of the reserves are in the Upper Devonian and 87% in the Mississippian. There is close correlation between reserves found and facies trends within the Mississippian Rundle Group. A widespread organic-rich source rock, the Exshaw Formation, provided the major charge for both Mississippian and Devonian reservoirs. Jurassic marine shales overlie the Mississippian in the southern part of the belt and form an effective seal and possible source rock. In the northern part of the belt, the Mississippian is overlain by Triassic sedimentary rocks in which reservoirs are present. Cretaceous sa dstones generally lack reservoir qualities and less than 5% of the reserves found to date are in the Cretaceous. The Outer Foothills are characterized by closely spaced listric thrust faults that repeat the Mesozoic section. Some of the thrusts cut deep enough to carry a single or multiple thrust slices End_Page 573------------------------------ of Mississippian carbonate rocks. Trap capacity is governed by horizontal displacement, vertical uplift, convergences of allochthonous and autochthonous structural strike, and probable seal quality to the thrust planes. Approximately 18 significant gas-bearing structures containing 5 tcf marketable reserves have been discovered. The surface geology of the Inner Foothills is characterized by outcrops of Paleozoic carbonate rocks and relatively undeformed Mesozoic strata. Usually two or more thrust sheets are stacked in a general anticlinal form and provide multiple objectives. To date, 14 gas-bearing structures have been discovered in this zone containing approximately 5.5 tcf of gas. The gas-bearing structures in the Waterton-Carbondale and Moose Mountain Panther River areas are typical. The gas-bearing post-lower Paleocene structures probably are related to the time of maturation of the major source rock and the west-to-east deformation of the southern Canadian Rocky Mountains. Despite the large areas of the Alberta Foothills belt in which exploration is restricted, it is estimated that 6 to 14 tcf of gas ma still be found. End_of_Article - Last_Page 574------------

Alberta Gas Chemicals, Inc. v. United States

Alberta Gas Chemicals, Inc. v. United States

An Alberta Gas Supply Response Model: Predicting Future Discoveries

Introduction Supply forecasting of natural gas has become one of the Canadian gas industry"s major problems. The ability to satisfy future domestic natural gas demand and to access export markets depends on forecasts of future reserves and deliver ability. These depend not only on the size of the resource base, but also on the rate at which resources are converted to reserves through successful exploratory drilling. Exploratory activity in turn is almost totally dominated by producer economics. This study attempts to synthesize the historic performance of the industry in Alberta using statistical techniques to identify the most important variables governing the generation of new gas reserves for the 1957–1977 period. By far the most significant variable found was the "PV factor"- a measure of the present value of gas in the ground in the average discovery made from time to time within each of nine Alberta gas supply areas. The PV factor simultaneously reflects costs, netbacks, success ratios and market lead times from the producer explorer viewpoint. An econometric model is proposed which exhibits excellent efficiency in matching historic reserves additions. The model lends itself to forecasting future reserves additions in Alberta making use of projections of netback prices," costs, success ratios and other variables. Background The nature of the natural gas industry is such that long-term forecasts of almost every aspect of the business are mandatory. Large investment in plant pipeline and distribution facilities requires the spreading of costs over two decades or- more in order to achieve reasonable unit cost levels. Project approvals from government regulatory agencies along with long-term financing arrangements can only be satisfactorily completed if adequate supply can be guaranteed with reasonable assurance for a like period of time. Appropriate energy policy can only be formulated by governments in possession of accurate forecasts of total gas reserves and supply. The strategic importance of natural gas as an energy source the involvement of municipal governments and the reliance of consumers on gas as a household fuel leads to regulation of the industry along public utility lines. However, the drilling of exploratory wells and the finding of new reserves is dominated by free enterprise, risk-taking and the profit incentive. It is characterized by the spending of billions of dollars on drilling dry holes in the ground-an industry that somehow seems beyond the ken of governments. Perhaps never have these differences been more clearly demonstrated than in the current federal-provincial energy controversy in Canada. The dramatic fluctuations in Canada"s natural gas industry over the past couple of decades are familiar to most of us:Prior to 1957, natural gas was produced in Western Canada for local utility use only; Alberta production was in the range of 300–400 MMCFD; natural gas was regarded as a by-product of oil exploration and production and priced accordingly at 10¢ per MCF or less. (See Figure 1 for historic gas prices.)From 1957 to 1973, the industry was characterized by high rates of-growth and a rapid buildup in reserves and production capability as sales increased in Eastern Canada and-the export markets through three major pipeline systems.