Medicine Hat Research Articles

Eastern Medicine Hat Gas Field: A Shallow, Upper Cretaceous, Bacteriogenic Gas Reservoir of Southeastern Alberta

Eastern Medicine Hat Gas Field: A Shallow, Upper Cretaceous, Bacteriogenic Gas Reservoir of Southeastern Alberta

ESR dating of Pleistocene fossil teeth from Alberta and Saskatchewan

Teeth collected from Pleistocene surficial sediments in southeastern Alberta and western Saskatchewan have been dated by electron spin resonance (ESR). The dates generally agree with the previously determined temporal sequence of the deposits, largely based on studies of fossil vertebrates and supplemented by some absolute ages, but the absolute ages of the oldest deposits appear to be much younger than previously estimated. Absolute ages (ESR) have been compared with faunal ages (using nomenclature of Stalker and Churcher): the age of Aftonian – early Kansan deposits at the Maser–Frisch site is 450 ± 30 ka; Kansan deposits in the Medicine Hat region range from 410 to 250 ka; Sangamon deposits at Mitchell Bluff are 67 ± 12 ka; middle Wisconsinan deposits at Empress, Alberta, are 34 ± 4 ka; postglacial beds near Medicine Hat give ages of 11 ± 2 ka (in agreement with 14C ages). At Wellsch Valley, however, ESR dates (280 ± 35 ka) are much younger than the age of about 1.5 Ma obtained from fauna, fission track, and paleomagnetics. This discrepancy may be due to late introduction of U into the teeth.

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.

Quaternary events in the Elkwater Lake area of southeastern Alberta

New data necessitate revisions in the Quaternary chronology of the Elkwater Lake area. Relicts of post-Middle Miocene preglacial erosion surfaces descend to the north and south from the Middle Miocene depositional surface on the Cypress Hills plateau. Both sets of surfaces are marked by oxidized weathering zones, locally culminating in relicts of preglacial paleosols. Both surfaces are overlain by a loess replete with cryogenic imprints. Deposition of this loess with cryogenic imprints shortly predates arrival of the Green Lake glacier at its terminus.The Green Lake end moraine marks the maximum extent of Laurentide ice in this area. Features previously attributed to the older Elkwater glacier can be explained with reference to proglacial meltwater action associated with the Green Lake glacier. The concept of Elkwater drift is no longer valid.Younger loesses, called upper loess, mantle nonglaciated terrain and the Green Lake end moraine and began accumulating just before Glacier Peak tephra was deposited (ca. 12 000 years ago). Because there is no evidence of weathering on the Green Lake end moraine beneath the upper loess, Green Lake drift dates from the late Wisconsinan. Most of the upper loess was deposited during the early Holocene and some since the Mazama volcanic eruption, 6600 years ago.Elkwater Lake reached its highest postglacial level, i.e., at least 6.6 m above the present level, well after the Mazama eruption, before spilling across the Green Lake end moraine into the Ross Creek system. This event irrevocably changed the regimen of Ross Creek, probably to its confluence with the South Saskatchewan River, at Medicine Hat.

Sand Bodies on Muddy Shelves: A Model for Sedimentation in Western Interior Cretaceous Seaway, North America: ABSTRACT

The continental shelf on the western margin of the Cretaceous Interior seaway was a muddy surface which bore abundant northwest-southeast trending sand bodies, up to 20 m (65 ft) thick and many km long (Medicine Hat, Mosby, Shannon, Sussex, Duffy Mountain, and Gallup Sandstones). These features resemble the storm-built or tide-built sand ridges reported from the modern Atlantic continental shelf, or from the Southern Bight of the North Sea. However, whereas modern sand ridges may rise from the Holocene transgressive sand sheet through overlying Holocene mud deposits to be exposed at the present sea floor, no modern examples are known where sand ridges are completely encased in mud, as the Cretaceous examples seem to have been. Hydrodynamical theory suggests that special circumstances may make it possible to build sand bodies from a storm flow regime whose transported load consists of sandy mud. Under normal circumstances, such a transport regime would deposit little clean sand. The sea floor is eroded as storm currents accelerate, but erosion ceases when the boundary layer becomes loaded with as much sediment as the fluid power expenditure will permit (flow reaches capacity). Deposition of the graded bed occurs as the storm wanes; the resulting deposit is liable to consist of a sequence of thin shale beds with basal sand laminae. However, slight topographic inequalities in the shelf floor may result in horizontal velocity gradients so that the flow undergoes acceleration and deceleration in space as well as in time. Fluid dynamical theory predicts deceleration of flow across topographic highs as well as down their down-current sides. The coarsest fraction of the transported load (sand) will be deposited in the zone of deceleration, and deposition will occur throughout the flow event. Relatively thick sand deposits, 20 to 50 cm (8 to 20 in.) can accumulate in this manner. Enhancement of initial topographic relief results in position feedback; as the bed form becomes higher, it extracts more sand from the transported load during each successive storm. Individual storm beds may tend to fine upward (waning current grading), but the sequence as a whole is likely to coarsen upward, reflecting increasing perturbation of flow by the bed form as its amplitude increases. Stability theory suggests that the end product of these processes should be a sequence of regularly spaced sand ridges on the shelf surface. However, sand bodies are localized in stratigraphic position and lateral distribution within Cretaceous shelf deposits. Upward-coarsening sequences are a widespread phenomenon in the Western Interior Cretaceous System, and the sand bodies appear to constitute localized sand concentrations within more extensive sandy or silty horizons. Especially widespread upward-coarsening sequences appear to be due to the close coupling between activity in the overthrust belt to the west and sedimentation in the foreland basin. In the proposed sequence of events, a thrusting episode increases relief in the source terrane as well as the load on the crust. Sedime tation at first dominates over subsidence, and initially the shelf on the western margin of the basin becomes shallower. As it does so, intensified wave scour on the shelf floor increases the amount of bypassing, which results in the deposition of increasingly coarser sediment, culminating in a sandy horizon. As relief in the hinterland wanes, subsidence overtakes sedimentation and the shelf subsides. Renewed thrusting begins the cycle anew. In a second mechanism for the formation of upward-coarsening sequences, tectonic uplift affects parts of the shelf as well as the hinterland. The initiation of Sevier or Laramide structural elements beneath the shelf, and the remobilization of other, older structures, creates submarine topographic highs. These highs cause slight sand enrichment over broad sectors by means of the process described above. The development of sand-enriched areas on the shelf floor by both mechanisms leads to the flow-substrate feedback behavior that builds large scale, elongate bodies of clean sand. End_of_Article - Last_Page 556------------

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 ...

Montana Business and Canadian Regionalism in the 1870s and 1880s

common assumption in the historiography of Canadian national policy is that the: Canadian Pacific Railway (CPR) forged the political, economic, and social bonds between the southwestern Canadian prairies and eastern Canada.1 In fact, this is not the case. The business activities of two Montana retail and government contracting businesses-T. C. Power & Brother and I. G. Baker & Company, which operated in the 1870s and 1880s in northern Montana and Alberta and Saskatchewan-indicate that the important ties between eastern Canada and the high plains were in place before the arrival of the CPR in 1883. Power & Brother and Baker & Company not only recognized these ties but also helped to establish them. They recognized Canadian territory as distinct from American territory, and both companies actively supported the Dominion government and encouraged it to assert its political authority in the southwestern prairies. Historians' distorted view of the impact of the CPR may be the result of assuming that the Canadian prairies were an American hinterland before 1883 and that the CPR drove companies such as Power and Baker out of Canada. Paul F. Sharp sums up this line of argument in his book Whoop-Up Country: The Canadian-American West, 1865-1885. He says, When the Canadian Pacific Railway reached Medicine Hat in 1883, the close ties between the American and Canadian areas were broken.2 The evidence provided by the T. C. Power papers, which have

Biostratigraphy and paleoecology of Pleistocene deposits (Riddell Member, Floral Formation, Late Rancholabrean), Saskatoon, Canada

The Pleistocene Floral Formation has been described from across central and southern Saskatchewan. In the Saskatoon area it comprises four distinct lithological units: a basal sand overlain by till and an upper sand overlain by till. The upper sand, here named the Riddell Member, contains the rich vertebrate composite Riddell fauna. The fossils are sufficiently distinctive to date the Riddell Member as Late Rancholabrean. This age is considerably younger than the age of the Wascana Creek ash and indicates that various deposits assigned to the Floral Formation are not correlative.Paleoecological analysis indicates that five ecological communities are represented in the composite Riddell fauna; the largest and most extensive habitat is the dry upland prairie. The sympatry of the represented taxa is unusual for central Saskatchewan and suggests that a temperate, equable climate prevailed. Paleoenvironmental reconstruction implies that the Riddell fauna is not synchronous with the Echo Lake fauna, but may be synchronous with the "Sangamon fauna" from Medicine Hat, Alberta.

Drilling and Fracturing Improvements for Low-Permeability Gas Wells in Western Canada

Summary Laboratory and field research have developed better drilling and fracturig fluids for extremely water-sensitive gas-producing formations in western Canada. Other improved techniques include perforating in dry hole, stage fracturing using baffles and balls, higher rates, higher sand concentrations, larger volumes, and immediate flowback with carbon dioxide assist. Introduction A Map of the area involved in this study of gas fields in the Alberta basin of southern Calberta is shown in Fig. 1. The first commercial gas production in Alberta began in the Medicine Hat area in 1890.1 Since then, many advances in completion and stimulation techniques have been made in Canada. The intent of this study is to present some of these recent improvements. A study2 of the geology of the Alberta basin shows a stratigraphic column with sediments ranging from Pleistocene through Cambrian covering more than 7,000 ft (2133 m), including the most productive Upper Cretaceous. The Upper Cretaceous, from the base of the Fish Scale formation to the Milk River formation, is about 1,200 ft (366 m). The lithology consists of a thick marine shale containing several sandstone and siltstone zones. These zones provide the majority of the gas production. Three of the main producers - the Milk River and Medicine Hat formations, the Second White Specks sands, and productive zones such as the Glauconite and Cardium - are shown in Fig. 2. The Medicine Hat formation and the Second White Specks sands are offshore bar types deposited in a high-energy environment. Reservoir qualities are fair to good, with permeabilities ranging from 0.1 to 5 md. The Milk River formation, which is usually thicker and more widespread than the other zones, consists of fine-grained sediments. These sediments were transported beyond the high-energy environment and deposited in quieter waters offshore, resulting in thin-bedded sands with high silt content interbedded with shale. The Milk River sand porosities vary from 10 to 15% in the better sand stringers. The net thicknesses of productive Milk River formation vary from about 1 to 30 ft (0.3 to 9 m) thick, with as much as 300 ft (90 m) gross thickness. Gas formations in Alberta usually contain high clay content, as shown in the petrographic and X-ray diffraction analyses (Tables 1 and 2) of typical cores from the Milk River, Medicine Hat, and Fish Scale formations. The gas formations in Alberta may contain 20 to 30% mixed-layer clays containing smectite and other clays (Table 2), causing these formations to be extremely water sensitive. Clays can be observed in the scanning electron microscope micrographs shown in Figs. 3 and 4. Fig. 3 is a micrograph of a typical Milk River formation core showing a pore space infilled with and surrounded by mixed-layer clays and chlorite with a pocket of siderite at the bottom left corner. The trace of siderite, an iron carbonate, was not detected by the X-ray diffraction analysis. A micrograph of Medicine Hat formation core, Fig. 4 shows a high concentration of mixed-layer clay with some kaolinite, illite, chlorite, calcite, and dolomite scattered throughout. The sand grains appear to be heavily coated with clays. The pore space is partially filled with mixed-layer and kaolinite clays.

Studies of Annular Gas Flow Following Primary Cementing

Abstract Annular gas flow has been a problem in the Alberta oilfields for several years. Much of the evidence for annular flow can be found in abandoned wells in southeastern Alberta and various producing wells in the Slave Lake area. This paper will review in 'some detail specific examples of gas flow problems and a cement slurry and cementing technique which has been successful in arresting this problem. Much research has been done in the area of cement slurry phase behaviour and the effects that this phase behaviour has on downhole formations. Results of laboratory testing and field applications will be presented as well as an overview of cement behaviour after cementing. Annular Gas Flow Problems in Alberta The flow of annular gas occurs in many different areas in Alberta because of various conditions. The following are a few problem areas which exhibit this phenonemon and their specific circumstances. Medicine Hat Area-Southeast Alberta Several formations in this area have gas leakage problems after cementing and require attention. The Second White Gas flow problems have occurred in the Milk River and Medicine Hat formations of southeast Alberta for years. The most critical problems have occurred after setting open-hole abandonment pings in shallow gas wells. These plugs cover most of the Milk River Formation and extend into the surface casing. Gas leakage is noticed in many cases after cementing. If the gas leakage is severe enough, then remedial action is required, such as drilling out and resetting the abandonment plug over the Milk River Zone. Problems have also occurred where gas is leaking between production and surface casing after production casing is set. This requires several expensive remedial steps, such as perforating and squeezing, and extensive service rig time. Lloydminster Area-Northwest Alberta Several formations in this area have gas leakage problems after cementing and require attention. The Second White Specks Formation near the Lloydminster area is the most critical. Other formations of concern are the Colony and Wabiskaw around Lac La Biche. Both of these areas experience gas leakage after cementing and must be dealt with at great expense to the operator. Grande Prairie-Northwestern Alberta This area has also experienced gas migration and channeling after cementing. Some of the problem areas occur in the Mussreau and Kakwa area. Annular Gas- The Unwanted Product Annular gas migration can occur in wells where the gas escapes at the surface and can be monitored. It can also occur underground by migration from a gas zone to another zone of lower pressure. Both systems are wasteful, dangerous and costly to repair. The problem of annular gas is not new. For many years, operators accepted the fact by completing wells and then performing remedial cement squeezes prior to producing. During the 1960s, extensive laboratory and field research was begun in an attempt to control the complex problem. Large-scale laboratory model studies evaluate several different drilling fluids, spacers, flushes and cement slurries with density, viscosity, flow characteristics, fluid loss and pipe configurations as the main parameters.

Fracturing Fluid Improvements For Gas Wells In Canada

Abstract Some of the Upper Cretaceous gas producing formations in the Alberta area are extremely water-sensitive, low permeability, shaley, marine sandstones. Offsetting the low porosity, permeability and reservoir pressure of these shallow gas sands are their widespread distribution and uniform characteristics over hundreds of square miles. With recent increases in the price of natural gas, and improvements in drilling and completion technology, the interest and drilling activity in these gas-producing formations has increased. Laboratory research and field operations have cooperated to develop better chemical additives for hydraulic fracturing fluids. These additives help reduce clay swelling and excessiveplugging caused by the migration of formation fines. Regained gas permeability tests using formation cores show the advantage of using these additives. Scanning Electron Microscope (SEM). X-ray diffraction, petrographic coreanalysis and fluid immersion tests were evaluated in this research study. Field results for wells fractured with improved fluids are included. Better gas production has resulted from wells fractured with these new fluids. Introduction The area of interest in this study is in the Alberta Basin in Western Canada. The three main provinces included in the basin are British Columbia, Alberta and Saskatchewan. The first commercial gas production in Alberta began in the Medicine Hat area in 1890,(1) Since that date, many advances have been made in Canada in completion and stimulation techniques. The intent of this study is to review some of the most recent improvements in these areas of technology. A study(2) of the Suffield Block in the Alberta Basin shows a stratigraphic column with sediments ranging from Pleistocene through Cambrian which covers over 7,000 feet (2.133 metres), including the most productive Upper Cretaceous. The Upper Cretaceous, from the base of the Fish Scales Formation to the Milk River Formation, is about 1,200 feet (366 metres). The lithology consists of a thick marine shale containing several sandstone and siltstone zones which provide the majority of the gas production. Three of the main producers here are the Milk River, Medicine Hat and Second White Specks sands. The Medicine Hat and the Second White Specks sands are offshore bar types which were deposited in a high-energy environment.Reservoir qualities are generally fair to good, with permeabilities ranging from 0.1 to 5 millidarcies. The Milk River Formation, which is usually thicker and more widespread than the other two zones, consists of finer-grained sediments. These sediments were transported beyond the high-energy environment and deposited in quieter waters offshore resulting in thin-bedded sands with high silt content interbedded with shale. The better Milk River sands may have penneabilities ranging from 0.1 to 1 mi11idarcy. The porosities vary from 10 to 15 per cent in the better sand stringers. The net thicknesses of productive Milk River Formation may vary from about 1 foot to 30 feet thick (0.3 to 9 metres), with as much as 300 feet (90 metres) gross thickness.

A Lesson in Boosterism: The Contest for the Alberta Provincial Capital, 1904-1906

Although 1905 marked a major transition in the political life of the old Northwest Territories, attention in Alberta's urban centres was focused not upon the larger questions raised by the granting of provincial status to the area, but rather upon the issue of which of the several competing communities would capture the title of provincial capital. Ambitious boosters in Red Deer, Calgary, Edmonton, Medicine Hat and a host of smaller settlements (such as Banff) coveted capital status for their particular city, town or even village as a symbol of its swelling importance and as an aid to further promotion. Many elements were called into play during the bitter capital campaign that followed the 1904 federal election including the geographical location, the future prospects and the business activities of the various aspirants. None of these factors proved to be critical in the final decision. The victor, Edmonton, emerged triumphant due in almost equal part to the persistent and aggressive actions of its boosters and to the inadequacy or failure of the urban promoters in rival centres. As boosters in Red Deer, Banff, Medicine Hat and Calgary discovered, success in the capital quest was dependent on much more than desire. By utilizing their advocates in both the federal and provincial political arenas and by thrusting their city into the public eye, Edmonton's community boosters gave their competitors an instructional session they would not soon forget.

The probable extent of Classical Wisconsin ice in southern and central Alberta

The margin of a former Laurentide ice sheet is traced through southern and central Alberta, from the Saskatchewan border southeast of Medicine Hat to beyond Rocky Mountain House, southwest of Edmonton. This margin, which marks the limit of a significant glacier advance or readvance, is thought to represent the maximum extent of Laurentide ice on the Canadian prairies during Classical Wisconsin time. In the south this margin follows a well-developed hummocky moraine; in the north it is indicated mainly by a discordance in trend of ice-flow markings, a disruption of drainage, and a change in maturity of topography on either side.

Method of Predicting the Initial Deliverability Of Shallow Gas Wells In Southeastern Alberta

Abstract Increasing emphasis is being placed on the development of the large natural gas reserves associated with the Milk River, Medicine Hat and Second White Specks formations in southeastern Alberta. Due to the low formation permeability encountered in these formations. short-term production test data often indicate a productive capability which is unrealistic when compared to the long-term performance of the well. This presents a difficult problem in designing the optimum gathering system and compression requirements. The purpose of this paper is to show how data from a properly conducted single-point production test of reasonably short duration can be used to predict the initial deliverability of a well completed in one of these formations and serve as a guide when designing a system for the development of shallow gas reserves. INTRODUCTION THE PRIMARY OBJECTIVE of any gas well test is to obtain sufficient information reflecting the well"s performance under varying conditions of flow in order to project future deliverability. This type of projection is necessary when preparing field development programs and designing gathering and compression facilities. Proper design of production facilities is important when considering the development of gas reserves associated with the Milk River, Medicine Hat and Second White Spects formations in southeastern Alberta. A low-deliverability shallow gas development is characterized by high well density and low pressure. Consequently, the gathering system and compression requirements usually absorb half the total development cost. Due to the low formation permeability associated with these shallow gas zones, initial flow rates rapidly decline to values substantially lower than those indicated from short-term production tests. This can lead to an over-design of production facilities and hence reduce the economic feasibility of the project. The method described herein will show how existing techniques of flow test analysis may be used to aid the operator in predicting the initial deliverability of a well completed in one of these formations and serve as a guide when designing a system for the development of shallow gas reserves. It will also be shown how this method may be used to determine the optimum flow time required when testing the wells. Method of Testing The modified isochronal back- pressure test is generally accepted as a reasonable method to use when evaluating gas well performance. However, when applied to the shallow, low-permeability zones of concern here, there are two major drawbacks. First, the bulk formation is not investigated within the short multi-point flow periods, but rather within a region close to the wellbore where flow characteristics are controlled primarily by the fracture system present. Second, as pointed out by Schopp(1), the extended flow period necessary: to reflect stabilization is not justified in these formations, where flow times of up to a "year or more could be required. It is recommended that a single-point production test be conducted on the well, allowing flow rate and pressure to decline with time. The well is flowed through a critical flow prover with a constant orifice size and the flowing pressures are recorded throughout the test.

Evaluation of Shaly Sands With Low Deliverability

Abstract Historically, wells encountering only shaly sands with low deliverabilities have been abandoned as dry holes, and exploration for such reservoirs has been considered uneconomical. With an increasing demand for hydrocarbons, however, shaly reservoirs such as the Second White Specks, Milk River, Medicine Hat and Belly River of southern Alberta and Saskatchewan, formerly considered uneconomical plays, have now become sought-after prospects. Evaluation of these very shaly reservoirs has proved to be neither simple not straightforward. Systems normally used for exploration and evaluation (logs, cores, drill-stem tests) were designed for clean sands with high deliverabilities. All these system have been hampered by the shale content of the sands. Recently developed methods of log analysis can define and adjust for shaliness effects. After adjustment for shaliness, the logs are capable of supplying such information on the reservoir thickness, hydrocarbon content, hydrocarbon type and identification of producible zones. Available logging programs and their interpretation, including an adjustment for shaliness, are discussed in this paper. The manner of interpreting logs, in the above shaly formations is developed in the discussion of the field examples, and the results of log interpretation are compared to the results of Core analysis and production tests. Introduction THE Second White Specks, Medicine Hat, Milk River and Belly River sand formations have several common characteristics. They extend from southwestern Saskatchewan through the Alberta plains as shalysand reservoirs with proven productivity. Generally their deliverability is low - less than 1 MMcf/D or 50 BOPD. Evaluation of these shaly sands is complicated by large variations in shale content, variable lithologies and low permeabilities. Current logging equipment and recently developed log interpretation techniques are capable of providing rapid, reliable evaluation of these zones. INTERPRETATION OF SHALY FORMATIONS The readings of many logs are affected by shaliness. The shalier a sand, the greater the effect. The formations named in the preceding paragraph can be productive with up to 50 per cent (by volume) of shale. Before any meaningful evaluation of these reservoirs is possible, a shaliness adjustment must be made. Shale, as seen by logs, consists of two components, silt and clay.(1) Silt is a very fine-grained lime, quartz, dolomite or other material that has infinite resistivity and may be radioactive. Clay is a hydrated mineral that is usually radioactive and has a low resistivity due to its ion-exchange properties. Both of these shale constituents affect log readings. Assuming the source rock to be sandstone, shaliness will cause the effects listed in the following table. (Table in full paper) In addition, the sonic and neutron logs are affected in sand-shale sequences by gas, which causes the sonic to read high and the neutron to read low. Lack of formation compaction also causes the sonic to read high. Log readings must be adjusted for shaliness effect, presence of gas, lithology and compaction before they can be used for accurate analysis. In the following examples, it is shown that an interpretation based on a single porosity log or a gamma-ray neutron log is not adequate for shaly formations.

Stimulation Techniques In the Milk River Formation, Medicine Hat

Abstract Recently, there has been a substantial level of activity in the shallow gas-bearing Milk River Formation of southeastern Alberta. Stimulation of the zone presents special problems, as the zone is soft, loosely consolidated, greatly affected by normal fracture fluids and low in permeability. Special materials and techniques have been developed to handle the particular problems presented by the Milk River Sand. This paper examines these techniques, including the use of carbon dioxide, large-mesh sand, clay-control agents and foaming agents, and estimates their effectiveness. The results of some treatments are discussed. Introduction THE MILK RIVER ZONE consists of two sections. The upper is a fine-grained, gray sandstone with interbedding of sandy clays and gray shales; the lower section is a light gray, medium-grained, cherty sandstone with streaks of sandy shale. The zone is found primarily in the southeastern portion of the province. Together with the overlying Pawkowki zone, the Milk River is equivalent to the Lea Park Formation. Zone thickness ranges up to 350 feet for the Pawkowki zone and 300 feet for the Milk River zone. Spectroscopic analysis indicates that the major component is quartzite, with small amounts of illite, kaolinite, chlorite and montmorillonite clays. This varies from well to well, and with depth, the deeper zone containing higher quantities of water-sensitive clays. Although there are very few cores cut on the Milk River zone, it appears that porosities range around 16 per cent, permeabilities are of the order of one milidarcy and water saturations are fairly high. Gas was first recovered from the Milk River zone in the year 1890. While exploring for coal in the Medicine Hat area, a well encountered considerable gas flows from a zone some 600 feet deep. Although little interest was shown in the Milk River section at that time, the gas discovery did spark gas well activity in the more prolific Medicine Hat Sand. However, activity was low because of the small size of local needs and because of the remoteness of any significant market. Of the few Milk River wells drilled in the early 1900's. one well, completed in 1911, continues to produce. Interest in the shallow gas, and particularly the Milk River zone, in southeastern Alberta remained dormant until 1941. At that time, the Department of National Defence drilled three wells to supply the Canadian Forces Base at Suffield with gas. By 1965 they had drilled some thirty wells, some of which are still on production for C.F.B. and Research Station use. Recent interest began late in 1968, with one well completed and put on production. The first frac treatment was also performed. Since that time, over two hundred fracture treatments have been conducted on the Milk River Sand with varying degrees of success. Various authors have described techniques of fracture geometry predictions, among them: Howard and Fast(2) Kiel(a), Geertsma and de Klerk'", As pointed out by Nierode et al(z), either of the most recent formulations give similar predictions of fracture geometry.

Petroleum Geology of Sweetgrass Arch, Alberta

The Sweetgrass arch is a positive structural feature extending from central Montana into southeastern Alberta. Rock units ranging in age from Precambrian Beltian to Late Cretaceous Montanan are exposed along the 350-mi axis. Three major elements can be highlighted: the South arch, which culminates in the Beltian exposures on the south end; the Kevin-Sunburst dome and the Sweetgrass Hills which dominate the center along the International Boundary; and the Bow Island arch which plunges northward into southern Alberta. Early exploration for hydrocarbons naturally was focused on the search for structural traps; such a large positive trend would be expected to have many faulted and domal anomalies. Active development work over the years proved that the stratigraphic trap predominated as the setting for hydrocarbon accumulation. Even the large closed structural anomaly of the Kevin-Sunburst dome does not entirely cause the entrapment of oil and gas there, but irregular porosity development in Mississippian carbonate rocks, and lensing and pinchout of Cretaceous sandstones more accurately account for the accumulations. The largest oil reserves on the arch are in a group of channel sandstones in the Lower Cretaceous basal Mannville Group, extending from the Cutbank field of Montana northward through the Taber, Hayes, and Bantry fields of Alberta. The middle Mannville Glauconitic-Moulton sandstones produce from a string of sandbars trending northward from the Darling area on the International Boundary through the Taber area and in scattered trends in the Jenner, Countess, and Hussar fields of Alberta. Large gas reserves are found in thin blanket sandstones of Late Cretaceous age, principally in the Medicine Hat and Second White Specks zones in the Alderson, Medicine Hat, Bantry, and Princess areas. Minor gas deposits are also in the Lower Cretaceous Bow Island Formation in long, narrow sandbars in the Pakowki Lake and Bindloss areas. A 300-ft-thick interval of silty and sandy shale in the Milk River Formation has been known to contain gas for some time, but, because of its low productive rate, only recently has this enormous deposit been developed. Since 1970 a small drilling boom has been under way to put this huge reserve on the market. The Milk River pool may be the largest single gas field in areal extent in western Canada.

Energy Resources For Future Electric Power Generation In Alberta, 1972-2001

Abstract Alberta's requirements for electrical energy a.re expected to increase almost ten-fold over the next 90 years. The Province has substantial reserves of gas, coal, conventional and synthetic oil as well as a number of potential hydro sites which could be utilized to meet future requirements for electrical energy. This paper examines a number of alternate allocations of resources to electrical generation in the over-all Alberta public interest. The analysis concentrates primarily on the utilization of coal or gas as a fuel source for thermal generation and examines the resultin impact on the Province's coal, natural gas and pipe-line industries as 'well as the costs to consumer of electricity. Introduction DURING THE PERIOD from September 19 to September 28, 1972, the Energy Resources Conservation Board (ERCB) held public hearings on Alberta's present and future requirements of energy and energy resources. A major issue was the extent to which future requirements of electric energy would or should be met from coal or from gas. This question is of considerable importance in the effective conservation and use of Alberta's energy resources and the public interest generally, and the Board's consideration of this matter resulted in the publishing of a report on the "Choices Among Energy Resources for the Generation of Electric Energy in Alberta".(1) The report contains a recommendation to the Lieutenant Governor in Council that the Government make certain broad policy decisions relating specifically to the choices among energy resources for future electric energy generation in Alberta. This paper is a summary of the fun report, with a few minor changes to reflect the most recent ERCB forecast of Alberta electric energy requirements. During the early part of the century electric energy was generated in Alberta by small hydro plants or small coal-fired thermal plants, each located near the load it served and with no electrical connection to other generating plants. Between the ends of the first and second world wars, a hydro energy storage and generation system was developed by Calgary Power Ltd. on the Bowe River. Transmission lines were built to interconnect the Bow Hydro system and the coalfired thermal plants at Edmonton, Calgary, Drumheller and in the Crowsnest Pass. The Lethbridge and Medicine Hat areas were served by gas-fired thermal plants and many towns had small local plants with internal combustion engine generating units. Since 1945, industrial expansion in Alberta, particularly the oil and gas industry, farm electrification, high-intensity lighting in urban centers and the proliferation of electric appliances, has caused a rapid increase in the demand for electric energy and has made the electrical interconnection of most load areas of the Province both desirable and economically feasible. It has now become advantageous to generate the base load energy with a few large thermal units running at nearly full load and maximum efficiency. The trend is to an interconnected generating system in which base load energy is generated from the most advantageous fuels and intermediate generation from units with the most advantageous operating characteristics and capital costs.

Development of Low-Productivity Gas Reserves, Southeastern Alberta

Abstract The drilling and completion practices utilized in the development of the Milk River and Medicine Hat zones in southeastern Alberta reflect the limited productivity and economics of the resulting gas production. The opera ting costs applicable to the surface handling of this gas are kept to a minimum through efficient utilization of wells, flowline, roads and surface equipment. Ultimate production for these zones is a function of individual well performance. Typical spacing to provide reasonable project lives are 320 acres for the Milk River development and 640 acres for the Medicine Hat pools. Initial productivity of the wells varies from 220 Mcf/D for a Milk River well to 500 Mcf/D for a Medicine Hat well. Production rate at abandonment could be as low as 20 Mcf/D. Typical recoveries for the Milk River and Medicine Hat zones are 2 Bcf/section. The profitability of a typical southeastern Alberta gas producing operation is critically related to capital and operating costs and particularly dependent on field operating practice. INTRODUCTION FOR THE PAST FEW YEARS, a significant portion of Alberta's natural gas drilling and development activity has been centralized in the southeastern portion of Alberta (Fig, 1). During 1971, approximately 25% of Alberta's additions to gas reserves were credited to this area. The same proportion is expected to apply to the reserve additions for 1972. As of August/72, the initial marketable gas forecast for the Milk River and Medicine Hat zones amounted to 2.8 Tcf. The recent study completed for the Alberta Government(1) indicates a gas reserve potential of 4 Tcf for the Suffield Block (currently a military reserve); once proven and developed, this could increase provincial gas reserves by 7%. The general industry activity forecast for southeastern Alberta for the next three years in currently undeveloped areas of reservoir potential could add an additional 4–6 Tcf of gas reserves to the provincial total. Production from these shallow low-pressure reservoirs dates back to the very beginning of Alberta's gas industry. Natural gas was first discovered in the Province northwest of the town of Suffield by a well drilled in 1883 to the Milk River Formation, The much publicized Medicine Hat Field was discovered in 1904. The performance of wells completed in the Milk River and Medicine Hat zones is typical of low-permeability reservoirs. Individual well rates are low. Recoveries are entirely dependent on the well productivity and the associated economics of production and compression. Because of these limitations, early production from the Milk River and Medicine Hat zones was primarily confined to local users. The low-cost energy source was quite successful, however, in attracting industry to the Medicine Hat area and was the beginning of the natural-gas-allied industry of the Province. As a matter of interest, in 1907, on a trip through the area and exposed to the many individual uses of natural gas, Rudyard Kipling exclaimed, "You people in this district have all hell for a basement".

Uranium-Series Ages of Some Quaternary Deposits Near Medicine Hat, Alberta, Canada

230Th and 231Pa dates were obtained on 10 bone samples from Quaternary deposits near Medicine Hat, Alberta. The youngest date so obtained (9500 ± 1500 years) agrees reasonably well with a radiocarbon date (11 200 ± 200 years) from the same site. In addition, where samples were collected from more than one bed at the same bluff the results are in the correct chronological order. A Sangamon bed containing chipped stones, thought to be artifacts, gave a date of 72 000 ± 6000 years, which is acceptable, though at the younger end of the previously estimated age range of between 200 000 and 70 000 years for the bed.In general, however, the results reveal large discrepancies with the estimated ages of the beds that yielded the bones. Although several causes for the discrepancies are possible, in two or three instances the uranium-series dates themselves appear to be incorrect, and the other dates must be treated with caution.