Goodarzi, Fariborz (FG&Partners Ltd, 219 Hawkside Mews, NW, Calgary, Alberta, Canada, T3G 3J4) | Ardakani, Omid Haeri (Geological Survey of Canada - Calgary) | Pedersen, Per-Kent (Department of Geoscience, University of Calgary, Calgary, Alberta, Canada, T2N 1N4) | Sanei, Hamed (Geological Survey of Canada - Calgary, Department of Geoscience, University of Calgary, Calgary, Alberta, Canada, T2N 1N4)
Canada has vast oil shale resources (estimated at 180 billion barrels proved recoverable oil shale reserve) similar to the estimated Canadian oil reserve of 179 billion barrels. These deposits consist of various oil shale types deposited in terrestrial, lake, and marine environments. These Canadian oil shale deposits are assessed under auspices of Canada/Israel Industrial Research and Development Program and Geological Survey of Canada for their possible use for extraction of hydrocarbon. The organic rich oil shale deposit with thickness of 60m are suitable for this purpose. This paper reviews the oil shale deposits of Arctic Canada from Ordovician to Carboniferous age. Ordovician shale of Baffin Island, Southampton Island, and Akpatok Islands consist of organic lean, calcareous deposits with variable thickness.
This paper describes a new technique for effective placement of delineationwells on the basis of the change of the uncertainty in the key global-reservesvariable. Uncertainty is summarized through the geostatistical framework. Theauthors develop a numerical and analytical methodology that is tested onsynthetic and real petroleum case studies. The implementation isstraightforward, and the results are promising. A methodology is developed toassist in delineation-well placement. Decisions for new-well locations areassisted with a quantitative measure of the expected reduction in globaluncertainty in the volume of original oil in place (OOIP). The availablerealizations are analyzed and processed to quantify the impact of wellplacement. Variograms and other required statistics are inferred from therealizations. As a result, a gridded map of impact values is produced, fromwhich locations with the highest impact are suggested for new-well locations.Numerical and analytical approaches for the impact-map calculation are proposedand compared. Pros and cons of each approach are summarized. The numericalapproach requires a large number of realizations for effective implementationof the impact map, which might not be practically achievable. On the otherhand, the analytical approach does not require many realizations and producesstable results. In most cases, only variogram models and current well locationsare needed for the analytical impact-map computation. Although computationaltime of this approach largely depends on the model size, some options aresuggested to reduce the cost. The analytical impact calculation is developedfor the OOIP model response, in which the petroleum reservoir is defined as acomplex geological architecture with multiple structural surface constraints.Several case studies, including a real-petroleum-reservoir example, demonstratethe use of the impact map for the assessment of new delineation-well locations.The developed tool is of significant help for well placement.
Duchesne, Mathieu J. (Geological Survey of Canada) | Brake, Virginia I. (Geological Survey of Canada) | Hu, Kezhen (Geological Survey of Canada) | Giroux, Bernard (INRS-ETE) | Walker, Emilie (Laval University)
This paper was prepared for presentation at the 1999 SPE Annual TechnicalConference and Exhibition held in Houston, Texas, 3-6 October 1999.
This paper presents a novel approach to modeling braided stream fluvial reservoirs. The approach is based on a hierarchical set of coordinate transformations involving relative stratigraphic coordinates, translations, rotations, and straightening functions. The emphasis is placed on geologically-sound geometric concepts and realistically attainable conditioning statistics including areal and vertical facies proportions. The equations for the eight-fold coordinate transformation, a new analytical channel cross section shape, and a real example with 20 wells are presented.
A characteristic feature of many fluvial reservoirs is the presence of sinuous sand-filled channels within a background of floodplain shale. Techniques for realistically modeling the spatial distribution of channels are necessary for reliable volumetrics connectivity assessment, and input to flow simulation. The approach presented here is applicable to stochastic modeling channel shapes and filling those shapes with porosity and permeability.
Modeling proceeds sequentially. Each major stratigraphic layer is modeled independently. The channel complex distribution, within a layer-specific stratigraphic coordinate system, is established first. Then, within each channel complex, the distribution of individual channels is simulated using appropriate transformed coordinate systems. This process is repeated down the hierarchy of geological units until the desired level of detail has been achieved. Finally, at the last coordinate system, petrophysical properties such as porosity and permeability are simulated with cell-based geostatistical algorithms within each facies.
This paper addresses the stochastic modeling of channel complexes and channels within a major reservoir layer. Multiple reservoir layers would be successively modeled and combined in a single reservoir model for volumetrics and flow simulation. At a higher level of iteration, multiple stochastic reservoir models could be constructed for assessing uncertainty.
An important feature of any approach to reservoir modeling is data conditioning. The data considered in this paper include lithofacies, porosity, and permeability data from wells, size and shape parameters of channel complexes, size and shape parameters of individual channels, vertical facies proportion curves, and areal facies proportion maps.
The approach presented in this paper has been inspired by the clear geometries observed at outcrops and as viewed from airplane windows in modern fluvial settings. There are similar object-based approaches documented in the literature. The approach adopted here is distinct from conventional object-based fluvial reservoir modeling in a number of ways, (1) the use of an explicit reversable hierarchy of coordinate transformations that is keyed to sound sequence stratigraphic concepts, (2) geologically-intuitive and accessible input data controlling channel sizes and shapes, (3) explicit control over vertically varying and areally varying facies proportions, (4) realistic asymmetric channel geometries, (5) realistic non-undulating channel top surfaces, and (6) integrated porosity and permeability models where the main directions of continuity conform to channel geometries.
Summary. The development of innovative exploratory drilling systems for Canada's harsh Arctic offshore areas over the past decade and future activity in these areas, including possible production concepts, are discussed. The results can be applied in other Arctic areas of the world, including offshore Alaska. This operating experience will advance drilling technology and serve as a basis for the design of Arctic offshore production and transportation systems. Unique technology has been developed and successfully used in the discovery of major accumulations of hydrocarbons. Continued technological advances are anticipated to have widespread Arctic applications in both exploratory and production operations.
Drilling has been successfully conducted in most of Canada's offshore areas despite the extremely harsh environmental conditions. During the past decade, technology has advanced very significantly particularly in the Beaufort Sea and Canadian Arctic Islands. particularly in the Beaufort Sea and Canadian Arctic Islands. Operating experience gained during the exploratory drilling phase is being used in the conceptual design of production systems. Undoubtedly, there will also be an evolution of technology during the development and production phases as the vast frontier reserves are exploited. Canada's offshore frontier areas typically have high costs and lengthy time spans between discovery and production. These factors present major engineering challenges for the design of safe, cost-effective, and timely exploratory and development systems. Confidence in the reservoir extent and predicted performance may permit large-scale development projects, while performance may permit large-scale development projects, while uncertainties may result in a phased approach where possible. The latter is attractive because earlier revenue is generated. Giant discoveries in the Beaufort Sea may not be essential to trigger development and a transportation system, because a combination of several pools may justify limited tankers or a small-diameter pipeline. Similarly, in such areas as the Grand Banks, phased pipeline. Similarly, in such areas as the Grand Banks, phased development with floating production platforms may be feasible. Artificial islands, first started in 1972, are still being constructed but with improved designs and equipment. A step forward has been the use of subsea berms on which concrete or steel segmented caissons have been placed. Integrated-type steel caissons have also been adapted for placement on subsea berms. One is one-half of a crude oil tanker and a second is a purpose-built steel caisson first used in 1984. Four drillships were converted and/or strengthened for Arctic service in the Beaufort Sea, and three have drilled since 1976. The second-generation floating vessel for the area is the Kulluk conical drilling unit, which began drilling in 1983 and has extended the operating season. In the Canadian Arctic Islands, drilling off artificially thickened ice in water depths exceeding 1,200 ft [365 ml has proceeded successfully since it began in 1973. On Canada's east coast, use of dynamically positioned vessels and iceberg towing have permitted seasonal drilling in positioned vessels and iceberg towing have permitted seasonal drilling in ice-infested waters. Production of oil from Hibernia and gas from Venture will be possible early in the next decade. Production of oil from the possible early in the next decade. Production of oil from the Beaufort Sea is also possible in the early 1990's and from the Canadian Arctic Islands in about the mid-1990's. Systems for such production will be discussed. production will be discussed. The focus will continue to be on exploratory drilling and delineation drilling for several years in most areas. Conceptual and preliminary engineering design for development will accelerate as new discoveries are made and others delineated. Wildcat exploratory drilling will also continue to satisfy exploration agreements and will tap the vast potential reserves of Canada's offshore areas.
The hydrocarbon potential of Canada's offshore frontiers has been recognized for several decades. Permits to explore for oil and natural gas were granted in several areas during the 1960's, when offshore drilling began on the east coast. Drilling in the Mackenzie delta and Canadian Arctic Islands (Fig. 1) in the 1960's was a forerunner to drilling offshore in those regions in the early 1970's. Encouraging hydrocarbon reservoirs have been discovered in all frontier areas except the west coast and Hudson Bay. The search has been primarily for oil in an effort to achieve self-sufficiency, security of supply, and economic returns. Significant reserves of nonassociated natural gas have also been discovered offshore and may be produced in conjunction with solution gas from offshore oil production and with nearby land-based gas reserves when a transportation system is available and demand and economic conditions warrant such production. Estimates of the potential recoverable oil and gas reserves for the frontier areas have recently been published by the Canadian federal government's Geological Survey of Canada (GSC) and are shown in Table 1.
Khan, Saeed U.; R J Brown and Associates (Far East) Pte Ltd, Singapore
The advances in offshore pipeline technology, in recent years, have been achieved by using innovative engineering to reduce construction risks and total capital costs. New design concepts and installation techniques namely: pipeline installation using the bottom tow method, pipe connections using the deflect-to-connect method and pipe trenching using marine plows have successfully been used in the North Sea, Canadian Arctic, South China Sea and Australian waters and which have resulted in significant cost savings in the material and installation costs.
With the spiraling hikes in the price of oil in the early seventies, the search and development of offshore oil/gas fields even in more non-traditional and remote areas with adverse environmental conditions, where equity capital and return ratios for such developments were previously considered significantly unattractive, was accelerated. The previously considered significantly unattractive, was accelerated. The requirements of high financial outlays for such offshore projects clearly dictated the necessity of cost savings in the materials and installation costs in order to make such developments economically viable. This obviously prompted concerted efforts towards the development of new design concepts, construction techniques and a so more sophisticated engineering analyses to reduce the construction risks and capital costs and also to alleviate maintenance and repair problems of such oil/gas transportation systems. The more severe requirements of pipelines long term stability in harsh environment and remote areas where maintenance and repair problems might result in higher costs than the actual installation cost put more emphasis on front-end engineering to obtain optimum solutions and cost-effective pipe installation and burial techniques. New design concepts and construction techniques have already proven their practicality and cost effectiveness especially in those areas where previously it was thought to be either too difficult or too expensive to develop.
This paper discusses the development and successful use of three such design concepts and installation and techniques for pipelines. These are:
- pipeline installations using the bottom tow method; - remote connections by the deflect-to-connect methods; - pipe trenching using the marine plows.
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I would like to begin my address by thanking the Society of Petroleum Engineers for the opportunity to speak to your Annual Petroleum Engineers for the opportunity to speak to your Annual Conference about Canadian Natural Gas prospects and how they fit into the energy requirements of the North American continent over the next 20 years. It seems somehow an appropriate topic since the theme of this conference is "Energy Frontiers".
We in Canada are very optimistic about our future energy potential. We are one of the few industrialized countries which has potential. We are one of the few industrialized countries which has benefited materially from the increase in real energy prices over the past 10 years, there is some truth in the comment that if OPEC had not existed Canada would have had to invent it. The fact of the matter is that Canada is a country which has a very large resource base and has a very exiciting energy future if energy prices are high but we are energy paupers if energy is cheap and abundant.
Our energy supplies are high cost compared to the costs of producing oil in the Middle East and if cheap energy prices, producing oil in the Middle East and if cheap energy prices, such as prevailed over the 1950's and 1960's, continued through the 1970's or 1980's much of our energy resource base would not be economic:
This paper describes the proposed Arctic Pilot Project, consisting of transmission, liquefaction terminal, shipping, and receiving terminal. Emphasis is on the unique problems resulting from the arctic location. Studies conclude that it is feasible to transport gas on a year-round basis from the arctic to the Canadian east coast.
The Arctic Pilot Project proposes to transport 250 MMscf/D (7 x 10(6) m3/d) of gas from Melville Island in the Canadian arctic to markets in eastern Canada. The gas will be pipelined from the Drake Point gas field to Bridport Inlet on the south coast Point gas field to Bridport Inlet on the south coast of Melville Island, where it will be liquefied and loaded on ice-breaking LNG carriers for transportation to a regasification terminal in eastern Canada. The economical and environmentally sound transportation of gas from the arctic revolves around the answers to two important and basic questions. 1. Can the Melville Island facilities be built on an economical and environmentally sound basis given that the location could be expected to result in conventional facilities that would cost at least five times that of facilities built in settled areas? 2. Can large ice-breaking LNG carriers operate year round in the arctic waters leading to Bridport Inlet? Petro-Canada, The Alberta Gas Trunk Line Co. Ltd. (AGTL), and Melville Shipping Ltd. have spent more than $11 million and 2 years finding the answers to these two questions and have concluded that the project is feasible, that the capital cost will be about $1 billion, and that the gas will be delivered to southern markets at a competitive price.
Melville Island Facilities
These facilities include the gas transmission line across Melville Island, the floating LNG plant and storage, and the Bridport shipping terminal. The lack of site specific information, which increases uncertainties in scope definition, and the high cost of on-site labor result in (1) arctic construction costs (using conventional methods) that are at least five times the costs in settled areas; and (2) a high degree of uncertainty in estimating final cost. The cost of on-site labor for this project will be minimized by building facilities to the greatest extent possible in settled areas. This approach minimizes the possible in settled areas. This approach minimizes the environmental and socioeconomic impact on the arctic.
The proposed gas transmission line is a 95-mile (160-km), 22-in. (560-mm) buried chilled gas line. This size line has a calculated capacity of 336 MMscf/D (9.54 x 10(6) m3/d) at the design inlet and outlet pressures of 1,200 psig (8268 kPa) and 900 psig (6200 pressures of 1,200 psig (8268 kPa) and 900 psig (6200 kPa). The cost estimate was prepared by AGTL, assisted by Canuck Engineering Ltd. The costs were based on proved construction techniques such as those used in proved construction techniques such as those used in the permafrost sections of the Aleyeska pipeline. The estimators have assumed construction only in the months of April, May, September, and October.
The successful development of a method for drilling offshore from a floating ice platform has enabled exploration wells to be drilled economically in the Canadian Arctic Islands. This method avoids the long wait for sophisticated offshore drilling vessels to be developed, financed, and built to operate in the severe ice conditions prevalent in the area.
The six gas fields discovered to date in the Sverdrup basin contain an estimated 13 Tcf of reserves (Fig. 1). For years geologists have recognized that much of the remaining undiscovered 90 to 260 Tcf of gas reserves in the Canadian Arctic Islands lie offshore. The Arctic Ocean in this area is covered with ice for 11 to 12 months of the year. Presently available drillships and semisubmersible drilling vessels are unable to reach these ice-infested waters. A drilling system mounted on an air-cushion vehicle that can move on top of the ice has been proposed, but is not yet under construction. Jack-up drilling platforms are not applicable because of excessive water depths. In any case, it is doubtful that a bottom-supported structure could withstand the powerful forces exerted by the thick ice sheet.
After several years of study it was determined that the ice sheet remains relatively stationary between the Arctic Islands from January to June each year. Further studies revealed that by progressively flooding and freezing in thin layers over a period of 1 to 2 months, an artificial ice platform could be built that was thick enough and strong enough to safely carry the weight of a small conventional land rig.
In March 1974, the first Arctic offshore gas well was drilled in 421 ft of water at W. Hecla N-62, some 7 miles west of Sabine Peninsula, Melville Island. In 1975 the technique was successfully used again off the east coast of Sabine Peninsula to drill East Drake I-55 in 467 ft of water and to extend the proven limits of the Drake Point gas field 7 miles offshore (Fig. 2). Plans are presently being made to drill three more offshore wells from ice platforms in 1976. One of these will be a 6,000-ft wildcat test.
Measurement of Ice Movement
The single most critical factor before ice-platform drilling can be undertaken is to know that the rig will not move significantly in relation to the ocean floor during the drilling period.
In March 1971, a study of horizontal ice movement at several prospective locations within 5 miles from shore was undertaken by triangulation from two onshore sites. A precision theodolite was used to measure angles to targets on the ice (Fig. 3). In later years, tellurometers were used to measure distance to the on-ice targets. This method supplemented theodolite measurements and allowed ice movement to be measured in obscure weather and up to 15 miles offshore. The same offshore locations were checked in subsequent years to ensure that there was no excessive fluctuation from one year to the next. In 1974 a geodometer was used in an attempt to measure ice movement at points up to 40 miles offshore. This instrument proved unsatisfactory because of unsuitable conditions in the Arctic.
The data gathered from these surveying methods generally indicated that horizontal ice movement was less than 20 ft over the period January to June and usually was less than 10 ft during the February-March-April drilling period. During 1974 and 1975 an acoustic method of measuring horizontal ice movement at points 40 to 50 miles offshore was developed (Fig. 3).