bluuebunny/crossref_metadata_2025_split huggingface dataset:
Modelling of Sand Production From Wells On Primary Recovery
Authors: Tremblay B. , Sedgwick G. , Forshner K. 
Published: March 2010

Abstract
Cold Production is a recovery process used in uncemented heavy oil reservoirs in which sand and oil are produced together under primary conditions. Sand production is known to be necessary in order to better access heavy oil reservoirs. The production of sand into a casing perforation was modelled experimentally using a horizontal sand pack. Heavy oil flowed through the sand and out the orifice at one end of the pack. The pack was scanned using an X-ray CT scanner. A high porosity (53%) channel (wormhole) was observed to develop in the sand pack above a critical pressure gradient. The sand cut was 44% (by volume) as the wormhole was developing. When the wormhole broke through the inlet, the sand cut decreased sharply. CT images taken at this time showed that only the loose sand within the wormhole started to be scoured away from the top down. The experimental observations suggest that the high sand cuts (20% to 40%) from wells at the start of cold production are due to the growth of wormholes while the sudden decrease in sand cuts (to 1% – 3%) indicates that the wormholes stopped growing. The residual sand cuts observed in the field are likely due to the scouring of the sand within the wormholes.

Introduction
Several heavy oil producers(1–5) have recognized that producing sand with oil significantly enhances primary recovery. The widespread use of progressive cavity pumps has been a key factor in making the Cold Production process economical by reducing the damage to wells caused by the pumping of sand. Elkins et al.(1) were among the first to suggest that high permeability channels, which they called wormholes, develop in oil formations when sand is also produced. The wells were located in the Southeast Pauls Valley Field, Gavin County, Oklahoma. They inferred the presence of wormholes from tracer tests, caliper surveys of the well before and after sand production, permeability calculations and the large volume of sand produced. Vonde(2) reported a significant increase in oil production rates when wells, initially completed with 16 mesh (0.40 mm) liner slots, were recompleted with 250 mesh (6.35 mm) liner slots. The sand cuts also increased to 10% by volume. The wells they investigated were located in the Cat-Canyon Field, California.
Injectivity tests, performed by Amoco, Canada(6), have shown that the concentration of an aqueous solution of flourescent dye did not change after being produced from an adjacent well. In a separate laboratory experiment, these investigators observed that the dye was adsorbed completely after flowing through a sand pack. Since the concentration of the injected dye did not change significantly in the injectivity test they inferred that the dye did not flow through a porous medium. They concluded that the dye flowed through a channel.Undiluted slugs of dye travelled at speeds up to 7 m/min. through what they believed were channel systems over 2 km in length that connected up to 12 wells(6). The wells were located in the Elk Point/Lindbergh fields, Alberta, Canada.
Lithium Silicate Scale In Oilfield Steam Generation
Authors: Zalewski W. , Bulkowski P. 
Published: March 2010

Abstract
At Wolf Lake, steam for in situ recovery of bitumen has been generated from produced water for over two years. Conventional softening of the produced water with warm lime followed by weak acid cation exchange without silica removal was inadequate to prevent scaling of the boiler tubes. Analysis identified the scale as lithium silicate, a material not previously identified as a scale in steam generation. Treatment of the produced water to lower the silica concentration below 50 mg/L has been found necessary and at 25 mg/L adequate to prevent scaling under the operating conditions at Wolf Lake. The concentration of lithium in produced waters is expected to vary with the reservoir, and to be a previously unrecognized determinant in the allowable level for silica in boiler feed water.

Introduction
In situ recovery of bitumen is done primarily by steam assisted methods. This type of bitumen production requires substantial volumes of water for steam generation. The steam to bitumen ratio may be as high as 6:1 which means that to produce 1 m3 of bitumen, 6 m3 of steam as water equivalent are required.
In many areas of heavy oil deposits, fresh water supplies are not readily available. Those fresh water supplies that are available are needed for a wide variety of uses, including domestic requirements, wilderness preservation, agriculture, recreation and industry. Moreover, increasing stress and more stringent quotas for fresh water usage are likely to be imposed on the heavy oil producer.
Therefore, the oil companies producing bitumen, recognizing the competing demands, must recycle the water that is co-produced with the bitumen.
This was recognized a long time ago and extensive research has been conducted on the treatment that could allow reuse of the so called produced waters.
Basically, produced water to be recycled for steam generation must be de-oiled and components that will form scale in the boilers must be reduced to innocuous concentrations.
Traditionally, for oil field steam generation, the scale forming elements/compounds that have to be treated have been calcium and magnesium (hardness), iron and silica.
There is a general consensus what level of hardness and iron is acceptable in the boiler feedwater (BFW) to the oilfields oncethrough steam generators: total hardness expressed as CaCO3 should be less than 0.5 mg/L and iron less than 0.1 mg Fe/L.
However, a much more complicated problem arises with silica. The prevailing opinion among water treatment specialists appears to be that if the feedwater is free of hardness and its alkalinity is high enough (ratio of alkalinity to SiO2 equal to 3:1 being the minimum) silica in the BFW is not a particular problem and higher levels can be tolerated.
The two main manufacturers of the oilfield boilers, Struthers TIW Limited and C.E. Natco, suggest that satisfactory operation of their boilers can be maintained with silica content 100 mg/L and 150 mg/L respectively(1,2): trouble free operations were reported with silica exceeding 200 mg/L(3).
What Causes Booms And Busts In Heavy Oil?
Authors: Miller K. 
Published: March 2010

Introduction
Development of Western Canadian heavy oil and bitumen production from the end of price controls in mid-1985 to today has been a roller coaster ride for oil companies and their employees. Activities in response to the current oil price drop suggest this trend is continuing. The results to the oil industry have been fragmented and inefficient efforts to advance technology and a need for repeated reorganization. The results to many employees have been insecurity, career disruption and general frustration. While some may point out that this period of time has seen a great deal of technical development, I feel that much more could have been accomplished under more stable circumstances.
It seems prudent that those of us in the heavy oil industry should periodically stop and ask ourselves why this cycling of activity occurs, and explore options for dampening the severity of the booms and busts. My main purpose in writing this article is to encourage candid dialogue.

Data Collection
When I was contemplating writing an article on this subject, I talked to a number of people working within the Calgary oil patch. Input was obtained from workers in industry, research, education and the government. Nearly everyone expressed strong opinions, but very few gave me the impression they wanted to be quoted or identified. From the perspective of the "soft science" of human behaviour, this high interest in expressing opinions but low interest in public ownership of them is likely an important piece of data.
Statistical data were not hard to locate, but most of these data were proprietary and likely unavailable for citation in this article. For example, some investment companies have detailed documents discussing current events in heavy oil and making predictions about its future. It is a little unnerving to read these sterile, economic prognoses of our chosen field of endeavour. One begins to wonder if the investment companies collectively have the ability to influence the economic state of the oil patch more than their workers do.
There are also a number of commercial analytical studies on the booms and busts experienced in the Canadian heavy oil industry. I will not try to duplicate or improve upon them. My statistics will be limited to noting the scale of the booms and busts by citing that over 26,000 Canadian workers appear to have been laid off between 1985 and 1994(1). The fraction working in heavy oil was not stated, but it was likely a significant number. It would also be very difficult to determine the number of these people who subsequently found employment back in the heavy oil field. Regardless of these unknown factors, it is apparent that significant disruption to the industry occurs during the boom and bust cycles.
Another important conclusion from the historic data is that all booms or busts will end within a few years. They should not be viewed as permanent.
Formation Evaluation of Triassic Naturally Fractured Carbonates In British Columbia
Authors: Aguilera R. 
Published: March 2010

Abstract
Triassic naturally fractured carbonates have proved to be very prolific in British Columbia. The fractures are of tectonic origin and were probably generated during the Laramide orogeny which created a series of compressional type structures.
The formation evaluation was conducted with a dual-porosity model which allowed estimates of matrix and fracture porosities from logs. Water saturation in matrix and fractures were calculated with the use of a statistical procedure without previous knowledge of water resistivity.
In addition, the interpretation led to estimates of bitumen content and percentages of siltstone, limestone and dolomite. The determination of the bitumen content is very important because bitumen can reduce effective permeability to gas quite significantly.

Log Interpretation
Well log analysis of Pardonet-Baldonnel formations was carried out with the use of a dual-porosity model which takes into account the presence of natural fractures and matrix porosity(1). Water saturation was calculated with the use of the P1/2 statistical procedure. P1/2 has a normal distribution for intervals that are 100% saturated with water. Hydrocarbon-bearing intervals deviate from the normal distribution.

Basic Approach
In this process, Archie's basic formation evaluation equations:
Equations (available in full paper)
In the above equations Φ?stands for total porosity (fraction), m is the porosity exponent of the composite system of matrix and fractures, I is the resistivity index, Rt is the true resistivity, A is a function of shaliness, F is the formation factor, Rw is water resistivity at reservoir temperature and "a" is a constant.
Analysis of Equations (4) and (5) indicates that (1) a crossplot of porosity or the response of a porosity log vs. Rt or (2) a crossplot of porosity vs. Rt/ Ash on log-log coordinate paper should result in a straight line with a slope of -m for zones with constant aRw and constant I (Figures 1-A and 1-B). For reservoirs with natural fractures, the value of m is smaller than the cementation exponent mb, determined from a matrix plug in the laboratory at simulated reservoir overburden conditions. This is reasonable because open unhealed fractures produce a reduction in tortuosity and cementation(4).
In many cases, it is possible to carry out the evaluation by crossplotting (Δt - Δtm) vs. Rt or (Δs - Δb) vs. Rt on log-log paper. In these crossplots Δt is sonic transit time as determined from the sonic log, Δtm is sonic transit time at zero porosity, ?s is grain density and Δb is bulk density.
When working with sonic logs in fractured carbonates the usual values of Δtm and Δtf no longer correspond to well defined physical parameters as they do in the case of the well known Wyllie(7) formula. Rather, these parameters have to be determined specifically for each case. We have found through experience that the sonic log is very useful in enlarged boreholes.
The value of m is determined by calculating the slope of the line drawn through the lower points in the log-log plot.
Carbon Dioxode Recovery: Large Scale Design Trends
Authors: Mariz C.L. 
Published: March 2010

Abstract
With renewed interest in enhanced oil recovery (EOR) as existing fields become depleted, there is renewed interest in supplying CO2 for flooding by CO2 recovery from flue gas. This paper examines key design and operating issues and trends for new unit designs which hold the potential for reducing the plant investment and operating costs associated with this source of CO2. The emphasis is on conventional processes using chemical solvents for CO2 removal (such as Fluor Daniel's ECONAMINE FGSM process) as these are either commercial or have been successfully pilot tested. Developments in new tower packings and solvents and their potential impact on plant and operating costs are discussed, as are the effects on these costs of the flue gas source. Operating and capital recovery cost data are provided for 1,000 tonne/d plants which would be a typical size for an EOR project.

Introduction
In the mid 1980s, when crude oil prices were over $30 per barrel, several plants came on line in West Texas in the U.S. which used 30 wt% MEA with special inhibitors to extract CO2 from boiler flue gas for use in EOR. However, when the price of crude oil dropped dramatically, these plants quickly became uneconomic and were scrapped. The then existing process licensors, Dow Chemical and Union Carbide, became less active in promoting these technologies and in 1989 Dow Chemical sold their FT-1 process to Fluor Daniel Inc. Fluor renamed the technology "ECONAMINE FG" and has since licensed three commercial plants, one 320 tonne/d plant at Bellingham, Massachusetts, U.S.A. (1989), a 150 tonne/d plant for Sumitomo Chemical at Chiba, Japan (1993) and a 90 tonne/d plant for Prosint Produtos Sint?ticos at Rio de Janeiro, Brazil (1997). All plants sell CO2 primarily to the food industry. The Bellingham plant, which has a gas turbine exhaust flue gas source, was constructed by Fluor. The Sumitomo plant was constructed by Mitsubishi Heavy Industries (MHI) with the flue gas source from a boiler fired by a variety of fuels including heavy fuel oils. The Prosint plant was owner-constructed and has a boiler flue gas feed source.
In addition, Fluor has performed a number of studies, several of which involved large-scale plants (1,000 tonne/d and larger). These studies were prompted by interest in using the CO2 for EOR and to avoid the new carbon tax being imposed in EC countries. In addition, the company designed two pilot plants for Japan which were used by the owners to study the process for greenhouse gas mitigation purposes. The results from the KEPCO pilot plant have been reported in the literature(1,2). Much of the KEPCO work is applicable to EOR applications as will be discussed later in this paper.
Interest in greenhouse gas emission mitigation has spawned a number of processes for capturing CO2 from boiler stacks that differ considerably from capture by chemical solvents. None of these processes are presently offered commercially and most will remain in the laboratory study phase at least for the near future.
SAGD Comes of AGE!
Authors: Butler R. 
Published: March 2010

Abstract
Canada's remaining resources of conventional crude oil are relatively slight and dwindling, but heavy oil and, particularly, bitumen resources are large. Their quantity approaches that of the resources of conventional oil in the Middle East. Without bitumen and heavy oil, Canada would face a growing requirement for funds to purchase foreign oil. This is already a severe problem for the United States whose large, unfavourable balance of trade stems from its need to import much of its crude oil.
Canada's success in producing bitumen by open pit mining of shallow Athabasca deposits by Suncor and Syncrude and by cyclic steaming at Cold Lake by Imperial Oil has already had a significant impact. However, although these approaches are economic, both have serious limitations.
Open pit mining is limited to shallow deposits and less than 10% of the total Athabasca resource is suitable. Also, open pit mining requires the disruption of the landscape and the handling of tonnages of tailings at least ten times greater than those of the produced bitumen. The disposal of the high clay content, "middling" stream from the hot water separation process which settles at a notoriously slow rate(1) and accumulates in tailings ponds that require prodigious areas is a severe environmental problem.
Imperial Oil's cyclic steaming has considerable environmental advantages since the reservoir solids are left in place. However, it is not a gentle process; the periodic injection of steam at pressures up to 14 MPa (2000 psi) sometimes results in well failure from the large cyclic, thermal, well-stresses. An important limitation of the process is that the recovery of the oil in place is only about 25%. Practical recovery processes for further recovery have not been defined(2). The consumption of fresh water equal in volume to the produced oil places a demand on the environment. SAGD gives a higher recovery and requires less water, less energy and fewer wells. Operation of the process is simpler than cyclic steaming because it is continuous and because of the fewer wells. Efficient recovery of heat from the produced fluids is possible and, because steam is required at a lower pressure, the cogeneration of electric power is more economic.

The SAGD Concept
Steam Assisted Gravity Drainage Process (SAGD) was introduced by the author and his former colleagues at Imperial Oil in the late 1970s(3, 4, 5). It was developed as a more systematic technique for the recovery of bitumen. The concept, shown in Figure 1, is now widely understood and is described in detail elsewhere(6, 7, 8).
It was predicted, from theory, and from scaled model experiments, that production rates of the order of several hundred to over a thousand B/day could be expected from well pairs about 500 m long; this has since been confirmed by the operation of full scale pilots-in Athabasca, in Cold Lake, in Peace River and in Lloydminster.

Essential Features of SAGD
Since gravity does not provide an adequate drive to move heated bitumens to a conventional well at an economic rate(9) horizontal production wells are used for SAGD.
Terra Nova: Building An Industry
Authors: Hawco C. 
Published: March 2010

Abstract
As Newfoundland's second offshore development, Terra Nova is building on the success of Hibernia, contributing to the birth of a new oil and gas industry in Newfoundland.
The decision to proceed with Terra Nova was announced on February 17, 1998. Project Sanction followed a Decision Report from the Canada-Newfoundland Offshore Petroleum Board, approving the Terra Nova development. This report was based on the culmination of a process that provided opportunity for individuals, concerned interest groups, and government to provide input into how the development of the Terra Nova oil field should proceed.
The Terra Nova oil field is located offshore, 350 kilometers east-southeast of St. John's, 35 kilometers southeast of Hibernia, in the most explored basin on the Grand Banks-the Jeanne d'Arc Basin. The field is composed of three fault blocks-The Graben, East Flank and Far East. It is estimated that the reserves for the Graben and East Flank are 370 million barrels of oil, with the undelineated Far East having the potential to add an additional 100 million barrels if successful.
For the Graben and East Flank a total of 24 wells are proposed. Should drilling prove the existence of economically recoverable oil in the Far East block, which appears to be a high probability, an additional five producers and five water injectors are anticipated. Starting in late 2000, Terra Nova expects that oil from the Graben and East Flank will be produced for the first six years at an average rate of 115,000 barrels of oil per day. In 2014, production will decline and be discontinued. If reserves are discovered in the Far East production could continue to 2017.
A Floating Production Storage and Offloading vessel (FPSO) is being developed as the production system for the Terra Nova oilfield. A first for Canada, the FPSO will be the size of three football fields laid end to end, with its hull at 291 metres long and 45.5 metres wide. The vessel's storage capacity is 960,000 barrels of oil, which translates into approximately eight days storage at peak production.
Daewoo Heavy Industries of Korea is under contract to construct the vessel. Detailed design is underway at the shipyard and construction of the hull will begin in August when the first steel plates will be cut. Following the start of vessel fabrication, the keel laying will commence in February 1999. The vessel will then leave Korea in November 1999, to arrive at Bull Arm in late January 2000, ready for the final hook-up phase to commence.
The Terra Nova FPSO will require four major modules between 1000 – 2000 tonnes each, as well as a turret, flare stack and miscellaneous deck assemblies. Two of the four major modules, the flare tower and deck assemblies will be fabricated at Bull Arm, Newfoundland. Additionally, the hook-up and commissioning of the FPSO and topsides will also take place at Bull Arm. The two remaining major modules will be fabricated by BARMAC, a company based in Scotland.