Southeastern Saskatchewan Research Articles

THE RAFFERTY-ALAMEDA PROJECT: MONITORING AND MITIGATION AFTER THE ENVIRONMENTAL IMPACT ASSESSMENT

Construction of the Rafferty-Alameda project in southeastern Saskatchewan was nearly completed in 1991 when a Canadian federal environmental impact assessment (EIA), activated and carried out in much controversy, was completed. Several recommendations were made with respect to mitigating and monitoring the potential negative impacts of the project. This paper reports the proponent’s response to the recommendations of the panel. Subsequent related events have had an impact on the project. An agreement with some landowners near the Alameda reservoir has led to the top 10 m of this reservoir being used only for flood control. Also, 1994, 1996 and 1997 were high flow years, resulting in the filling of both reservoirs by the end of the 1997 spring season, much sooner than envisioned at the time of construction of the project. The panel’s main concern was the potential deterioration of water quality and its impacts on fish and wildlife habitat. Ponding of water in the two reservoirs was expected to increase nutrient levels, leading to anoxic conditions, with resultant negative effects on both fish and waterfowl habitat in the reservoirs. Reduction of flow downstream of the reservoirs was expected to negatively impact fish and waterfowl habitat downstream of the project in North Dakota. The high flow regime of the past three years has led to good quality habitat for both fish and waterfowl. The fish population has increased significantly in both reservoirs, leading to enhanced recreational fisheries. However, mercury levels in fish have risen, and sampling and fish consumption advisories are in place. Loss of waterfowl habitat has been mitigated by the high reservoir levels, particularly since the main species of waterfowl can breed in the fenced-off areas around the reservoirs. The reserved lands purchased by the proponent are good habitat for other wildlife species, including deer and other ungulates. Overall, the project is producing many of the benefits originally claimed by the proponent, benefits magnified by the high flow regime of the past few years. The proponent has successfully instituted several measures to mitigate some of the negative impacts.

Hydrologic and climatic implications of a multidisciplinary study of late Holocene sediment from Kenosee Lake, southeastern Saskatchewan, Canada

Sediment lithology and mineralogy, as well as ostracode, plant macrofossil and stable isotope stratigraphies of lake sediment cores, are used to reconstruct late Holocene hydrologic changes at Kenosee Lake, a relatively large, hyposaline lake in southeastern Saskatchewan. Chronological control is provided by AMS radiocarbon ages of upland and shoreline plant macrofossils. All indicators outline an early, low-water, saline phase of lake history (4100–3000 BP), when the basin was occupied by a series of small, interconnected, sulfate-rich brine pools, as opposed to the single, topographically-closed lake that exists today. A rapid rise in lake-level (3000–2300 BP) led to the establishment of carbonate-rich, hyposaline lake conditions like those today. Lithostratigraphic data and ostracode assemblages indicate peak salinities were attained early in this period of lake infilling, suggesting that the lake-level rise was initially driven by an influx of saline groundwater. Lake-level and water chemistry have remained relatively stable over the last 2000 years, compared to earlier events. Because of a lack of datable organic material in sediments deposited during the last 2000 years, the chronology of recent events is not well resolved. Plant macrofossil, lithostratigraphic and ostracode evidence suggests that lake draw-down, accompanied by slightly higher than present salinites, occurred sometime prior to 600 BP, followed by peak lake-level and freshwater conditions. This most recent high lake stand, indicative of a high water table on the surrounding upland, may also have led to the establishment of an extensive cover of Betula in the watershed, possibly in response to paludification. Ostracode assemblages indicate that peak freshwater conditions occurred within the last 100 years. Since historically documented lake-level fluctuations correlate with decadal scale climatic fluctuations in the meteorological record, and late-Holocene hydrologic dynamics correspond to well documented climatic excursions of the Neoglacial and Little Ice Age, Kenosee Lake dynamics offer insight into the susceptibility of the region's water resources to climate change.

Abstract: Dolomitization in the Bakken Formation in South Eastern Saskatchewan, Canada 

Abstract: Dolomitization in the Bakken Formation in South Eastern Saskatchewan, Canada 

Abstract :Development, Optimization and Future Potential of a Giant Oil Field - A Case History: Weyburn Field Southeastern Saskatchewan

Abstract :Development, Optimization and Future Potential of a Giant Oil Field - A Case History: Weyburn Field Southeastern Saskatchewan

Reconstruction of glacial Lake Hind in southwestern Manitoba, Canada

Glacial Lake Hind was a 4000 km2 ice-marginal lake which formed in southwestern Manitoba during the last deglaciation. It received meltwater from western Manitoba, Saskatchewan, and North Dakota via at least 10 channels, and discharged into glacial Lake Agassiz through the Pembina Spillway. During the early stage of deglaciation in southwestern Manitoba, part of the glacial Lake Hind basin was occupied by glacial Lake Souris which extended into the area from North Dakota. Sediments in the Lake Hind basin consist of deltaic gravels, lacustrine sand, and clayey silt. Much of the uppermost lacustrine sand in the central part of the basin has been reworked into aeolian dunes. No beaches have been recognized in the basin. Around the margins, clayey silt occurs up to a modern elevation of 457 m, and fluvio-deltaic gravels occur at 434–462 m. There are a total of 12 deltas, which can be divided into 3 groups based on elevation of their surfaces: (1) above 450 m along the eastern edge of the basin and in the narrow southern end; (2) between 450 and 442 m at the western edge of the basin; and (3) below 442 m. The earliest stage of glacial Lake Hind began shortly after 12 ka, as a small lake formed between the Souris and Red River lobes in southwestern Manitoba. Two deltas at an elevation of 450 were formed in this lake. At the same time, the Souris Lobe retreated far enough to allow glacial Lake Souris to expand farther north along the western side of the basin from North Dakota into what was to become glacial Lake Hind. Three deltas were built at an elevation above 460 m in the Canadian part of this proglacial lake. Continued ice retreat allowed the merger of glacial Lake Souris with the interlobate glacial Lake Hind to the east. Subsequent erosion of the outlet to the Pembina Spillway allowed waters in the glacial Lake Hind basin to become isolated from glacial Lake Souris, and a new level of glacial Lake Hind was established at 442 m, with 5 deltas built at this level by meltwater runoff from the west. Next, a catastrophic flood from the Moose Mountain uplands in southeastern Saskatchewan flowed through the Souris River valley to glacial Lake Souris, spilling into Lake Hind and depositing another delta. This resulted in further incision of the outlet (Pembina Spillway). A second flood through the Souris Spillway from glacial Lake Regina further eroded the outlet; most of glacial Lake Hind was drained at this time except for the deeper northern part. Coarse gravel was deposited by this flood, which differs from previous flood gravel because it is massive and contains less shale.

Actual Versus Predicted Horizontal Well Performance, Weyburn Unit, S. E. Saskatchewan

Abstract The Weyburn Unit, located in the southeastern corner of Saskatchewan, has over 80 horizontal wells. These wells are producing from a complex, naturally fractured reservoir that has been on waterflood for over 30 years. Accurate prediction of horizontal well performance is required for waterflood development planning, facilities design and marketing. For more precise estimates, simulation modelling has been the tool of choice to incorporate the reservoir anisotropy and the effect of having a multi-layered reservoir. Specific area models were built, but the Weyburn Unit spans 83 Sections with over 160 potential horizontal well locations making full field simulation impractical. Therefore, analytical models, because of their flexibility, were used to estimate the performance of horizontal wells field-wide. To validate predictions from both the simulation and analytical models, all available information sources were combined. These included:off-trend vertical well performance,existing horizontal well performance in the Weyburn Unit and other Midale beds pools, andgeological models. As a result of this work, we were able to calibrate a published analytical model to better predict horizontal well performance in this complex reservoir and to optimize the design of future' wells. Introduction The Weyburn oil pool, located in southeastern Saskatchewan, was discovered in 1954 (Figure 1). By 1960, the field was fully delineated with vertical wells on 32 ha (80 acre) spacing. In 1964, it was placed on waterflood with 151 inverted nine-spot patterns. A year later, oil production peaked at 7,500 m3/d and then declined until 1985. Production decline was arrested with the drilling of 157 vertical infill wells from 1985 to 1992. About 27% of the 178 106m3 original-oil-in-place has been produced to date. A medium gravity crude oil (27 ° API) is produced from the Midale Beds of the Mississippian Charles Formation. These beds are divided into an upper chalky dolostone called the Marly and a lower limestone called the Vuggy. The original inverted nine-spot waterflood has been successful in sweeping the Vuggy, but has not been efficient in sweeping the Marly. The vertical infill wells targeted the Marly zone. By 1991, the number of potential economic vertical infilllocations was diminishing, so the Unit turned to horizontal drilling technology for further development. During 1991 and 1992, six horizontal wells were drilled, experimenting with different geological environments and well orientation. The lessons learned from this pilot were used in the design and execution of the commercial horizontal well development in 1993. Through a cost/benefit analysis it was decided to drill long horizontal wells (1,000 m) that parallelled the fracture trend. These wells were drilled underbalanced. This development drilling is expected to continue throughout most of 1995 bringing the total number of horizontal wells in the Weyburn Unit to over 80. Accurate forecasts of horizontal well production rate and reserves allow:a proper assessment of economic reward with infill drilling,a framework in which capital and operating costs can be controlled, andlead time to arrange oil transport to markets.

Horizontal Wells In The Rosebank Alida Beds Pool, Saskatchewan

Abstract The Rosebank Alida Beds (Mississippian) pool of southeastern Saskatchewan is a mature oil field that has produced close to 5 million m3 of light oil since discovery in 1955. Oil trapped at the subcrop is produced from two carbonate reservoirs: a lower unit with fine intercrystalline porosity and an upper unit with coarse vuggy porosity. The pool was originally developed on 32 ha (80 acre) spacing. Original pressure has been largely maintained by natural water influx. Vertical as well as horizontal infill wells have not resulted in significant interference with production at offsetting original vertical wells. Nonetheless, several vertical infills have productivity that is considerably lower and water-oil ratio that is significantly higher than offsetting original wells. In contrast, seven of eight horizontal wells drilled in the northern part of the pool have been remarkably successful in increasing productivity and reserves. The seven successful horizontal wells had first-year oil productivity averaging 40 m3/d, close to three times that of surrounding vertical wells drilled 25 to 40 years earlier, and initial water-oil ratios of 0.3, comparable to that of the original wells. Five of the horizontal wells have average ultimate reserves of 80,000 m3/well compared to an average 67,500 m3/well for 26 surrounding vertical wells. In the area studied, the vertical wells are expected to recover 37.5% of the original oil-in-place. The five horizontal wells are expected to recover an additional 8.6% of OOIP for a total recovery of at least 46.1%. Geology and reservoir properties are important considerations in the location of successful horizontal wells. At Rosebank, among other considerations, horizontal wells oriented parallel to the paleotopographic ridge, presumably parallel to the main fracture trend, will recover more reserves than those oriented' transverse to the ridge. Introduction The Rosebank pool occurs along the subcrop of the Mississippian Alida Beds on the sub-Watrous unconformity approximately 225 km southeast of Regina, Saskatchewan (Figure 1). The carbonate-hosted oil pool at a depth of 1,070 m was discovered in 1955 and had produced 4.8 × 106 m3 (30.2 × 106 STB) of light oil to December 31, 1990. The pool has a strong water drive. The southern part of the pool, developed on 32 ha (80 acre) spacing in 1955 and 1956, was unitized in 1971. The northern part of the pool was drilled on 32 ha (80 acre) spacing in 1966 and 1967. Several vertical infill wells on 16 ha (40 acre) spacing were drilled over the years with the greatest activity from 1987 to 1991. Horizontal development began in late 1990 and ten horizontal wells had been drilled to December 31, 1993. Results of the first horizontal well were reported by Jamieson(l,2). Horizontal drilling of the carbonate reservoir at Rosebank has resulted in a remarkable increase of oil production in a mature oil field that has been on production for almost 40 years. There has been considerable controversy as to whether ultimate reserves are increased through horizontal infill drilling or whether there is simply an acceleration in the production of oil that would be produced by vertical wells over a longer period of time.

Improved forage production following western snowberry (Symphoricarpos occidentalis Hook.) control with metsulfuron methyl

Two 6-yr studies were conducted in southeastern Saskatchewan to evaluate 2,4-D, Metsulfuron methyl (Metsulfuron) and a mixture of 2,4-D + Metsulfuron for the long-term control of western snowberry. Western snowberry is a small shrub that grows in dense stands in rangelands and pastures and acts as a physical barrier to grazing. At the study site, the shrub was growing with native grasses and forbs. Metsulfuron applied at 15 g a.i. ha−1 effectively controlled western snowberry for 6 yr. Control with Metsulfuron was better than with 2,4-D because Metsulfuron killed the crown of the shrub. Control was not improved when 2,4-D was added to Metsulfuron, and at low levels of Metsulfuron the presence of 2,4-D in the mixture rendered Metsulfuron less effective, resulting in a higher canopy cover. Grass production averaged over years and experiments was 788 kg ha−1 for the check and increased to 1328 kg ha−1 after Metsulfuron was applied at 15 g ha−1. Forb production was not affected by the treatments. Key words: Western snowberry, Symphoricarpos occidentalis, metsulfuron methyl, 2,4-D

Predictions of Horizontal Well Performance In a Mature Waterflood, Weyburn Unit, Southeastern Saskatchewan

Abstract The results of a parametric numerical simulation study led to the development of selection and screening criteria which were used to define horizontal well candidates within the Weyburn Unit of southeastern Saskatchewan. The relative impact of several reservoir and wellbore properties on horizontal well productivity was assessed. This study shows that Weyburn horizontal well performance is improved if reservoir permeability is high, void age replacement is maintained, good communication exists between the two main producing zones, and effective wellbore length is maximized. The well spacing, location and position in the more highly oil-saturated zone were also found to contribute to the productivity of a horizontal well. As a result of this and other engineering and geological work, three successful horizontal wells were designed and drilled in the Weyburn Unit in late 1992. These wells have produced over 19,000 m3 of oil in the first three months of production. Many of the findings of the parametric study, such as well orientation, expected watercut and optimum positioning within the pay, were confirmed by this drilling program. Introduction The Weyburn Unit is located approximately 130 km southeast of Regina, Saskatchewan (Figure 1). The field covers approximately 180 km2 and consists of 627 producing wells and 162 water injection wells. Oil is produced from the Midale Beds of the Mississippian Charles Formation which were deposited on a shallow carbonate shelf in the Williston Basin. The reservoir is subdivided into an upper Marly and a lower Vuggy zone (Figure 2). The Weyburn field was discovered in 1955 and was completely delineated by vertical drilling by 1960. In 1964, the field was unitized and a waterflood was implemented using inverted nine spot patterns oriented in the NE-SW direction. Between 1985 and 1992 over 150 vertical infill wells were drilled within the unit resulting in substantial incremental oil recovery. The infill drilling program concentrated on improving the walerflood performance and vertical wells were drilled on both 24 ha and 16 ha spacing's within some areas of the field. To date, only 25.8% of the 178 million stock tank m3 of medium gravity crude oil have been produced. The remaining oil in place represents a significant target for improved recovery schemes such as horizontal drilling. FIGURE 1: Location of Weyburn Unit. (Available in full paper) In 1991, a horizontal drilling program was conducted in the Weyburn Unit. Three wells were drilled in different parts of the unit to evaluate the technical feasibility of applying horizontal drilling technology. With the number of economically attractive vertical infill targets declining, it was concluded that the future development of the unit would be dependent on the successful application of this technology. Although promising, the results of this drilling program fell far short of what had been anticipated with only one well (10Hz-II) producing any appreciable amount of oil. The low overall productivity of these wells and the success of other wells in the area drilled by other operators led to the development of the parametric numerical simulation study, which is the subject of this paper.

Cavity and fracture systems in Winnipegosis buildups (Givetian), Tableland area, southeastern Saskatchewan

ABSTRACT The formation and later filling of cavities (reticulate, isolated and caverns) and fractures (types A and B) in carbonate buildups of the Winnipegosis Formation was a critical phase in the porosity history of these carbonates. Reticulate cavities (up to 2 cm high and wider than the 3.5 in diameter core) with flat subhorizontal bases and irregular roofs formed beneath reoriented, cemented grainstone crusts. Isolated cavities (up to 6 cm high and wider than the core), which are irregular in shape, formed contemporaneous with deposition of peloidal packstones and wackestones and algal laminated bindstones. The presence of isopachous cements, radiaxial fibrous cements and peloidal sediments in many cavities suggests that they formed in open marine conditions. Caverns, up to 2.5 m high, probably formed by dissolution when the buildups were subaerially exposed. Type A fractures, which occur in the upper 10 m of the buildups on their windward margins, probably formed as a result of tectonic fracturing or oversteepening of a semilithified margin. Type B fractures, which occur as networks of thin veins, formed by compaction or by water escaping through semilithified sediment. Cavity and fracture systems are filled with micrite and silt that formed during subaerial exposure of the buildups. RESUME La formation et le remplissage par la suite de cavites (reticulees, isolees et caverneuses) et de fractures (types A et B) dans les accumulations de carbonates de la Formation Winnipegosis a ete une etape importante de l'histoire de la porosite de ces carbonates. Les cavites reticulees (jusqu'a 2 cm de hauteur avec un noyau de plus de 3,5 cm de diametre) avec des constituants alcalins sous-horizontaux a fond plat et des plafonds irreguliers formes sous les croutes de calcaire a debris jointifs cimentes reorientes. Les cavites isolees (jusqu'a 6 cm de hauteur avec un noyau plus large) de formes irregulieres, formees pendant la meme periode avec des depots de packstone peloidal, de wackstone et de bindstone algulaires lamines. La presence de ciments isopaques, de ciments fibreux radiaxiaux et de sediments peloidaux dans les nombreuses cavites suggerent que ces dernieres ont ete formees dans des conditions marines exposees. Les cavernes, jusqu'a 2,5 m de hauteur, ont probablement ete formees par dissolution lorsque les accumulations ont ete exposees a l'air. Les fractures de type A, presentes dans les 10 m superieurs des accumulations, ont probablement ete formees a la suite d'une fracture tectonique ou du surraidissements d'une marge semilithifiees. Les fractures de type B, presentes comme reseaux de filons minces, formees par tassement ou par l'echappement de l'eau par les sediments semilithifies. Les systemes de cavites et de fractures sont remplis de micrite et de limon qui ont ete formes pendant l'exposition a l'air des accumulations. Traduit par Marie Louise Tomas

Petrographic Thermal Maturity Assessment of Winnipegosis (Middle Devonian) and Bakken (Devonian-Mississippian) Formations, Southeastern Saskatchewan

ABSTRACT The Middle Devonian Winnipegosis Formation and the Upper Devonian to Lower Mississippian Bakken Formation in southeastern Saskatchewan have been studied to assess their thermal maturity levels with respect to petroleum generation. Fluorescent and white incident light microscopy has been used to determine vitrinite reflectance in oil (%Ro) and maximum wavelength fluorescence emissions (lambda max) for alginite macerals in the two formations. Vitrinite reflectance for the Winnipegosis Formation ranges from 0.33 to 0.86 %Ro. A reflectance-depth profile indicates that a low and a high paleogeothermal gradient probably affected Winnipegosis strata in the region of study. Peak hydrocarbon generation for Type II kerogen source rocks in the Winnipegosis Formation is marked by a vitrinite reflectance of near 0.70 %Ro and by a red shift in alginite lambda max values toward longer wavelengths (> 570 nm). Thermal maturity levels of the Bakken Formation range from immature to marginally mature (0.30 to 0.68 %Ro). Based on vitrinite reflectance and alginite lambda max values, a relatively low and a relatively high paleogeothermal gradient also seems to have affected the Bakken Formation shales. A low maturation gradient is proposed for western borehole locations whereas the higher gradient is proposed for eastern borehole locations. Minor hydrocarbon generation has occurred in the western portion of the study area where radioactive-element decay from phosphatic particles has stimulated microscopic thermal anomalies and more extensive bitumen formation. RESUME La Formation Winnipegosis du Devonien moyen et la Formation Bakken du Devonien superieur au Mississippien inferieur du sud-est de la Saskatchewan ont ete etudiees pour evaluer leurs niveaux de maturite thermique en ce qui a trait la production de petrole. La microscopie par lumiere incidente fluorescente et blanche a servi pour determiner le taux de reflectance vitrinite dans le petrole (%Ro) et les emissions de longueur d'ondes fluorescentes maximum (lambda max) pour les maceraux alginites des deux formations. Le taux de reflectance de la Formation Winnipegosis varie de 0,33 a 0,86 %Ro. Le profil de profondeur de reflectance indique qu'un gradient paleogeothermique inferieur et superieur a probablement touche la couche Winnipegosis dans la region etudiee. Le sommet de la generation d'hydrocarbure pour les roches meres de type II kerogenes de la Formation Winnipegosis est marque par un taux de reflectance de pres de 0,70 %Ro et par le changement au rouge des valeurs lambda max d'alginite vers des longueurs d'onde plus longues (> 570 nm). Les niveaux de maturite thermique de la Formation Bakken varient d'immature a tres legerement mature (0,30 a 0,68 %Ro). Selon les valeurs de taux de reflectance lambda max, un gradient paleogeothermique relativement bas et un autre relativement eleve semblent avoir egalement touche les shales de la Formation Bakken. Un faible gradient de maturation est propose pour les emplacements des trous de forage situes a l'ouest alors qu'un gradient plus eleve est propose pour les trous de forage situes a l'est. Une faible quantite d'hydrocabure a ete generee dans la partie australe de la region etudiee ou un element de desintegration radioactif de particules phosphatees ont stimule les anomalies thermiques microscopiques et la formation plus etendue de bitumes. Traduit par Marie Louise Tomas

Horizontal Wells: Successes And Failures

Introduction To date, about 6500 horizontal wells have been drilled around the world in various field applications. In Canada alone, about 750 horizontal wells were drilled from 1988 until 1992. In 1993, about 700 horizontal wells were estimated to be drilled in Canada(1,2). Thus, a large amount of data exists to review the field performance of horizontal wells. The objective of this article is to briefly review the field applications of horizontal wells under various reservoir conditions, especially for Canadian reservoirs. A review of economically successful and unsuccessful wells is used to develop a list of important parameters that need to be considered for selecting commercially successful applications of horizontal wells. Field Applications To date, horizontal wells have been used in naturally fractured reservoirs to enhance well productivity by intersecting natural fractures. Moreover, horizontal wells have also been used in oil reservoirs to minimize water and gas coning, and in gas reservoirs (with bottom water) to minimize water production. Additionally, in Canada alone, over five hundred horizontal wells have been drilled in high permeability, heavy oil reservoirs. Horizontal wells have also been used in low permeability gas reservoirs to enhance drainage volume and therefore, to enhance cumulative gas production per well, so as to make them economic. Horizontal wells have also been used in thermal oil recovery(3), not only to produce highly viscous bitumen in the Cold Lake area(4), but also to produce heavy oil in the Tangleflags North area(5). Other applications of horizontal wells include miscible flooding in the Keg River and Pembina Nisku reef reservoirs to produce a thin oil zone sandwiched between the top solvent zone and the bottom water zone(6,7). Recently, horizontal wells have also been used in waterflood applications. Relative to oil applications, only a few gas production wells are drilled horizontally, probably due to low gas prices over the past few years. Recently, in Canada, horizontal wells have also been used in gas storage reservoirs to enhance short term productivity to meet peak gas demand. The main applications in Canada are significantly different from those in the U.S. In the U.S., out of about 4500 wells, over 2500 horizontal wells were drilled in the low permeability Austin Chalk formation and about 200 wells have been drilled in the fractured Bakken Shale formation. The objective here was to intersect natural fractures and improve well productivity. In the U.S., except in Alaska, California, and the Gulf-coast, very few horizontal wells are drilled for water and gas coning applications. Thus, the typical U.S. application is for a low permeability, naturally fractured formation. In contrast the majority of Canadian applications are for water or gas coning situations. Almost 45% of the Canadian wells to date have been drilled in heavy oil fields in Saskatchewan and Alberta. About 40% of the wells have been drilled in medium to light oil fractured carbonate reservoirs in Southeastern Saskatchewan. Several heavy oil pools with bottom water zones (which could not be produced economically using vertical wells) have been made economic by drilling horizontal wells.

Geographic Variation in Yellow-Headed Blackbirds from the Northern Great Plains

We assessed geographic variability in morphology among Yellow-headed Blackbirds (Xanthocephalus xanthocephalus) collected from breeding populations in Minnesota, North Dakota, and South Dakota in the United States and Alberta, Manitoba, and Saskatchewan in Canada during spring. Both male and female Yellow-headed Blackbirds tended to be larger in the more northern breeding populations. Males collected in Manitoba and southeast Saskatchewan tended to be more like populations from the United States, whereas other populations in Saskatchewan and Alberta populations were morphologically similar to each other. For females, however, only the Manitoba population was similar to the U. S. populations, and the females from the southeastern Saskatchewan were similar to other Saskatchewan birds. Southeastern Saskatchewan appears to represent a transitional region between northwestern and southeastern breeding populations of Yellow-headed Blackbirds.

Prevalence of childhood asthma across Canada.

A large cross-sectional study provided an opportunity to estimate the prevalence of childhood asthma in several regions across Canada. In 1988, approximately 18,000 questionnaires were distributed to the families of 5-8 year old children in 30 communities from the following six regions across Canada: the interior of British Columbia, southeastern Saskatchewan, southwestern Ontario, the central region of Ontario, southern Quebec, and the Maritimes (Nova Scotia and Prince Edward Island). These communities were free of point-source air pollutants and selected to represent a range of ambient sulphate concentrations. In all 14,948 questionnaires were returned representing an 83% response rate. Currently present, physician-diagnosed asthma was reported for 4.7% of children by their parents. Persistent wheezing was reported for 13% and persistent cough for 5.9%. Asthma was most common in the two Maritime provinces (7.4%), and least common in British Columbia (3.3%) and Quebec (3.4%). Similar regional differences were seen for persistent cough, persistent wheeze, and also hospital separation rates for asthma which were approximately 800 per 100,000 for the Maritimes and 396 per 100,000 for British Columbia. Differences persisted despite adjustments for several host and environmental (indoor and outdoor) characteristics. The east coast of Canada may be an endemic area of asthma in Canada. If confirmed by objective measures of asthma, a detailed aetiologic investigation could enhance understanding of this phenomenon and the major environmental determinants of asthma morbidity in general.

Simulation of Horizontal Well Performance While Waterflooding the Weyburn Midale Beds Pool of Southeastern Saskatchewan

Abstract The feasibility of infill drilling and waterflood modification in the Weyburn Midale Beds Voluntary Unit No.5 in Southeastern Saskatchewan was assessed.Detailed geological and reservoir simulation studies were conducted toinvestigate the various alternatives for further development drilling usingvertical and horizontal wells. Various single well radial, two-dimensional and three-dimensional models wereemployed to better understand the main reservoir drive mechanisms duringprimary and waterflood operations. The models were calibrated by historymatching of actual pool production performance. Simulation results clearlyestablished the need for infill drilling, particularly with horizontal wells.which outperformed vertical wells by an order of magnitude. An 800 m horizontalwell was drilled and placed on production in September 1991. The earlyproduction results of the tirst horizontal well are compared to the modelpredictions. Introduction The Weyburn Field is located in the province of Saskatchewan, approximately 130km southeast of the city of Regina as shown in Figure 1. The Weyburn Midale Beds Pool was discovered in 1955 with the completion of Central-Del Rio Ralph1-06-7- 13W2M1 and was subsequently developed on 32 ha spacing. The main Weyburn Unit was formed in 1963 and an invented nine-spot waterflood scheme wasimplemented in April 1964. In 1977, Saskoil Weyburn 4-11-7-1 3W21M was drilled and completed in the Midale Beds extending the Weyburn Midale Beds Pool beyond the boundary of the main Weyburn Unit. Development of this extension by various operators has proceededsince 1977 on 32 ha spacing. In 1988, the Weyburn Midale Beds Voluntary Unit No.5 (the "Unit") was formed (Figure 1) and waterflood operations commenced in March 1988. A successful 40-acre infill well located at 3-11-7-13W2M wasdrilled in 1989 and prompted the initiation of an infill drilling: andwaterflood optimization study. The main objective of the study was to evaluatethe potential of further development drilling and modification of thewaterflood to increase production and improve the oil recovery from the Unit. Asecondary objective was to evaluate the merit of horizontal infill well versusvertical infill wells. Soon after the completion of the study in 1990, five more 40 acre verticalinfill wells were drilled and one existing producer was converted to waterinjection. Most of the five wells were drilled for both Midale and Frobishnerproduction and some wells were dually completed in both zones. Based on therecommendations of the infill drilling study, an 800 m horizontal well wasdrilled and put on production in September 1991. Currently the Unit consists of13 vertical producers, one horizontal producer, four water injectors and onewater source well. FIGURE 2: North Weyburn: permeability vs. porosity. Graph Available In Full Paper. Pool. The drilling, completion and initial production of the first horizontalwell in the Unit are also discussed in the paper. Geology The Weyburn Field is situated along the northeastern flank of the Williston Basin in southeastern Saskatchewan(1). The oil accumulation isconfined by an upper anhydrite seal and, at the Midale Beds subcrop, by lowpermeability Jurassic Red Beds silts.

Waterflood and CO2 Flood of the Fractured Midale Field (includes associated paper 22947 )

Summary The considerable remaining oil target in the naturally fractured Midale field prompted a major reservoir and recovery mechanism study in the mid-1980's. Included in the study were the detailed evaluation of 20+ years of waterflood history and the implementation and analysis of a tertiary miscible CO2-flood pilot. The study showed that tertiary miscible flooding should not necessarily be precluded for naturally fractured reservoirs. Introduction The 500-million-bbl Midale oil field is part of a trend of large Mississippian oil accumulations located in southeastern Saskatchewan along the northern margin of the Williston basin. The field was discovered in 1953 and developed on 80-acre spacing. In 1962, Midale was unitized for waterflooding, with eighty-three 320-acre inverted nine-spot patterns (Fig. 1). The reservoir section in Midale consists of a heavily fractured vuggy limestone overlain by a less fractured chalky dolomite. Waterflood performance is dominated by these oriented vertical fractures, which typically are spaced 1 to 4 ft apart. Production wells located "on-trend" from injectors(aligned with the fractures) showed sharp early response to waterflood. In contrast, response of "off-trend" producers was smooth and delayed. Oil produced to date represents recovery of 20% of the original oil in place(OOIP); ultimate waterflood recovery is predicted to be only 24% OOIP. The current water cut in the mature operation is about 80% (Fig. 2). Although the reservoir is fractured, well productivities are modest, with average production rates of 75 to 100 STB/D-well. Typical EOR screening criteria suggest that naturally fractured reservoirs are poor candidates for miscible CO2 flooding. Despite this rule of thumb, the favorable reservoir geology combined with the substantial EOR target at Midale persuaded the field owners to study implementation of CO2-flood technology. A 4.4-acre tertiary miscible CO2-flood pilot was conducted during 1984–89. Field-scale waterflood and pilot-scale CO2-flood results were history matched with a dual-porosity reservoir simulator. Field-scale CO2-flood recoveries are predicted to be an incremental 20% OOIP. The high CO2-flood recovery results from the favorable interaction of the different layers within the reservoir. The bulk of the large tertiary target is trapped in the chalky dolomites in the upper reservoir section. Although most of the CO2 is injected into the underlying heavily fractured limestones, gravity forces cause the CO2 to rise and come in contact with the oil in the dolomites. Based on pilot results and simulation studies, a $40-million commercial-scale CO2 flood began in Feb. 1992 in 10% of the unit. Geology The 4,600-ft-deep, gently dipping productive carbonates are overlain and underlain by impervious anhydrite beds.1The productive interval typically consists of a limestone (the Vuggy) overlain by a dolomite (the Marly), as shown in the type log in Fig. 3. The Marly zone has a layered geometry with good lateral continuity between wells. The Vuggy is less layered and more laterally discontinuous. The average gross thicknesses for the Vuggy and Marly zones are 40 and 30 ft, respectively; reservoir development is 20 ft in the Vuggy and 10 ft in the Marly. The reservoir is quite consistent in total thickness, varying from 60 to 80 ft across the majority of the unit. Internally, however, the Vuggy/Marly thickness ratio does vary considerably. The Vuggy zone contains two distinct rock types, intershoal and shoal. The intershoal Vuggy is present over the entire unit, while shoals have limited areal extent. Indeed, the majority of the unit is devoid of shoal Vuggy. However, where shoal Vuggy does exist, it dominates performance because of its high permeability. Intershoal Vuggy consists primarily of peloidal and bioclastic packstones containing mostly interparticle porosity. The shoal Vuggy consists of peloidal grainstones that display visually dramatic vugular and interparticle porosity. Despite these large pores, porosity values in the shoal and intershoal are very similar, ranging from 10% to 15%. Typical intershoal permeabilities are 1 to 10 md, with shoal permeabilities an order of magnitude higher. The Marly zone consists primarily of dolomitic wackestones and mudstones, with the mudstones forming the best reservoir rock. Porosity, which ranges from 20% to 35%, is predominantly intercrystalline with secondary amounts of pinpoint vuggy porosity. Marly permeability ranges from 1 to 10 md.

Full‐waveform processing and interpretation of kilohertz cross‐well seismic data

High‐frequency, cross‐well seismic data, from the Midale oil field of southeastern Saskatchewan, are analyzed for direct and reflected energy. The goal of the analysis is to produce interpretable sections to assist in enhanced oil recovery activities ([Formula: see text] injection) in this field. Direct arrivals are used for velocity information while reflected arrivals are processed into a reflection image. Raw field data show a complex assortment of wave types that includes direct compressional and shear waves and reflected shear waves. A traveltime inversion technique (layer stripping via ray tracing) is used to obtain P‐ and S‐wave interval velocities from the respective direct arrivals. The velocities from the cross‐well inversion and the sonic log are in reasonable agreement. The subsurface coverage of the cross‐well geometry is investigated; it covers zones extending from the source well to the receiver well and includes regions above and below the source/receiver depths. Upgoing and downgoing primary reflections are processed, in a manner similar to the vertical seismic profiling/common‐depth‐point (VSP/CDP) map, to construct the cross‐well images. A final section is produced by summing the individual reflection images from each receiver‐gather map. This section provides an image with evidence of strata thicknesses down to about 1 m. Synthetic seismograms are used to interpret the final sections. Correlations can be drawn between some of the events on the synthetic seismograms and the cross‐well image.

The effects of tillage systems and crop sequences on soil bulk density and penetration resistance on a clay soil in southern Saskatchewan

Concern has been expressed that reduced tillage systems may lead to excess soil compaction, negatively impacting on crop growth. The objectives of this study were to determine the effects of tillage systems zero (ZT), minimum (MT) and conventional tillage (CT) and crop rotations on soil bulk density and penetration resistance after 4 yr on an Indian Head heavy clay soil, in southeastern Saskatchewan. Moisture content was similar among tillage systems, except for slight differences in the lower soil depths with crop rotation. Penetration resistance and bulk density of a heavy clay soil were increased in the surface 10 cm of the soil by ZT as compared to CT management. However, in the deeper soil zones, tillage system did not consistently influence either bulk density or penetration resistance. Inclusion of peas in the crop rotation had a moderating effect on bulk density and penetration resistance, while inclusion of flax in a continuous rotation increased bulk density and penetration resistance in the surface soil profile. At the 30- to 45-cm depth, ZT had a lower bulk density than CT or MT in the rotation which included fallow, possibly because the tillage operations associated with the cultivated fallow led to compaction in the deeper soil zone. Penetration resistance was great enough in the deeper soil zone in all tillage systems to restrict rooting, but difference due to tillage treatment or cropping rotation was not sufficient to markedly influence crop production. Key words: Penetration resistance, bulk density, crop rotation, tillage

THE RAFFERTY-ALAMEDA PROJECT AND ITS ENVIRONMENTAL REVIEW: STRUCTURES, OBJECTIVES AND HISTORY

The Rafferty-Alameda project in south-eastern Saskatchewan has been fraught with controversy, even though it is not large by usual standards. Most of the controversy has arisen in the federal environmental review process and its relationship to the timing of the provincial review and project construction. This paper gives a description of the project and its objectives, an outline of the project history with emphasis on significant events, and a summary of the recommendations of the second Federal Environmental Review Panel.The paper begins with a description of the basin, the project, and the project objectives. The objectives of the project are to store water in two reservoirs which will be released so as to satisfy the apportionment requirements for flow to the USA, provide some cooling water for the Shand coal-fired thermal power station, control flooding along the Souris River basin mainly in North Dakota but also in Saskatchewan, and enhance irrigation and recreation opportunities, plus satisfy other less-critical needs.The paper next addresses the history of the project, concentrating mainly on the impacts of court decisions on the EIA process and how that impacted the construction schedule for the project. The main decision was the one by Justice Cullen that established the Federal Environmetal Assessment Review Guidelines Order as law. This established federal authority and responsibility in the assessment process applied to projects impacting federal jurisdiction.The paper then goes on to discuss the recommendations of the panel. The specific recommendations of the panel concentrated on the expected changes in the timing and magnitude of flows available downstream of the project and the resulting impacts on conditions there. The panel found that significant impacts could occur on the water quality and hence on the waterfowl, fisheries, and community water supplies, also downstream in North Dakota and Manitoba. Recommendations to mitigate these effects as given in the panel report are discussed.The paper concludes with a discussion of the general recommendations of the panel report. These include the need for basin-wide planning, particularly in the Souris River Basin, the general need to consider cumulative impacts of all projects in the Basin, the need for federal priorities which encourage environmental stewardship and the need for coordination between federal and provincial environmental assessments.

Empiracally Derived Capillary Pressure Data from Core Analysis: Applications to Modeling Pore Geometry in Carbonate Reservoirs, Southeastern Saskatchewan

Empiracally Derived Capillary Pressure Data from Core Analysis: Applications to Modeling Pore Geometry in Carbonate Reservoirs, Southeastern Saskatchewan