bluuebunny/crossref_metadata_2025_split huggingface dataset:
Experience With Fireflooding In Countess 'B' Pool, Alberta Reservoir Aspects
Authors: Metwally M. 
Published: March 2010

Abstract
This paper discusses the reservoir aspects of the Countess ‘B’ Fireflood Pilot Project in southeastern Alberta. The Countess 'B J Pool is a Glauconitic channel sandstone and has been under waterflood since 1973. The fireflood pilot was initiated in 1983 and the operation is expected to continue until 1991. This 16 ha inverted five-spot includes one injector and four producers.
The pilot was designed to determine the level of incremental recovery that could be achieved from the process application and to obtain operating experience from a reservoir containing 28 ° API oil. An extensive program of well testing and fluid analysis has been conducted to identify and evaluate the pilot performance.
The Countess ‘B’ Fireflood Pilot has broken new ground in a number of ways. Results suggest that a waterflooded light oil reservoir can be fireflooded successfully. A mineralogical examination of a post-combustion core indicates that firefront temperature in this pool is 300 °C to 400 °C and oil is effectively displaced. To the end of 1988, the cumulative burned volume represented 20% of the pilot volume. To date the pilot has achieved most of its objectives and will likely achieve the remaining objectives prior to its termination in 1991.

Introduction
The Countess Upper Mannville ‘B’ Pool is located in Township 19, Range 16W4M, approximately 20 km west of the town of Brooks. Alberta (Fig. I). This pool is part of the Countess Latham trend and was discovered in 1965. The pool is operated by PanCanadian Petroleum Limited and jointly owned (50%) with LL&E Canada Ltd. The pool is currently in the later stages of waterflood.
Extensive engineering and laboratory studies conducted on the Countess ‘B’ Pool during the period 1978–80 concluded that fireflooding application is feasible. A pilot project commenced in January 1983 in Part II of the Countess ‘B’ Pool to evaluate the fireflood process and is expected to continue until 1991.

Reservoir
In the Countess ‘B’ Pool, oil production is from a series of southeast/northwest trending channel sands. These sands are elongate and narrow with a length of up to 5 km and a width ranging from 300 m to 1500 m. Thickness varies from 1 m to 12 m. Based on lithology and stratigraphic position, the sandstones of the Countess ‘B’ Pool are part of the "'Glauconitic" of the Upper Mannville Group. Part II of the Countess "B' Pool, as shown in Figure 2, is the largest of these sands.
Following are the average reservoir properties of Pan II:depth 1080mgross pay thickness 8 mporosity 25%permeability 800 mDinitial oil saturation78%initial reservoir pressure 9.6 MPareservoir temperature 38 °Coil gravity28 °C APIoil Viscosity @ reservoir conditions 6 cpinitial formation volume factor 1.124
The Glauconitic sandstones of the Countess ‘B’ Pool are generally fine- to medium-grained, moderately well sorted and composed of quartz and chert with minor feldspar and decrial clay. Cementation is mainly by authigenic clays, including kaolinite and to a lesser degree illite.
Effects Of A Thin Skin At The Front On Composite Reservoir Well Tests
Authors: Ambastha A.K. , Ramsey H.J. 
Published: March 2010

Abstract
A radial composite reservoir model is used to analyze well-tests from a variety of enhanced oil recovery projects, geothermal reservoirs, and acidization projects. A composite reservoir is made up of two or more regions. Each region has its own rock and fluid properties. Also, dynamic phenomena, such as phase changes and multi-phase 1ow effects in a region near the front, can cause a sharp pressure drop at the front. Such a sharp pressure drop is modelled as a thin skin at the front in this study. An analytical solution for the transient pressure behaviour of a well in a two-region composite reservoir with a skin at the front is obtained using the Laplace transformation.
Analysis shows that a thin skin at the front can explain a short duration pseudo-steady state corresponding to the inner swept volume for small mobility and storativity contrasts. The effects of is skin at the front are similar, to the effects of storativity ratio. Thus, neglecting a thin skin at the font can cause large errors in parameter estimation using a type-curve matching method. Also, graphical correlations are presented for the time to rile end of pseudo-steady state behaviour corresponding to the inner swept volume with a skin at the front. Such correlations should help in selecting a proper pseudo-steady Cartesian straight line for data analysis.

Introduction
Figure 1 shows a schematic diagram of a two-region, radial composite reservoir. The inner and outer regions of a composite reservoir have different, but uniform rock and fluid properties, and are separated by a discontinuity. The distance R is the front (or discontinuity) radius, which is an important parameter sought from well tests in composite reservoirs. Eggenschwiler et al.(I) presented an analytical solution in Laplace space for the transient pressure behaviour of a well producing (or injecting) at a constant rate from (or into) a two-region, radial infinite composite reservoir. Horne et a(2) extended them Eggenschwiler et a, solution to finite composite reservoirs.
This study considers transient pressure derivative behaviour of a well in a two-region, composite reservoir with an infinitesimally thin skin at the front. The effects of a thin skin at the front on the transient pressure and pressure derivative behaviour of a well in a composite reservoir is considered important because a thin skin at the front may be a practical approach to model the following physical situations:vapourization at the discontinuity while injecting cold water in a hot geothermal reservoir;condensation at the steam front such as in steam injection projects;cases where a transition region is apparent. For in situ combustion cases, Onyekonwu(3) observed a transition region.Pressure profiles presented in Figures 6.8 and 6.11 of Reference 3 suggest that the system may be modeled as a two-region reservoir with a thin skin at the discontinuity; andsimulated CO2 flooding results show that from 600;0 or the over-all pressure- drop occurs in a small region around the front(4).
Medium-Radius Lateral Drilling Applications In Canada
Authors: Heaton Mark , Rotel Wayne 
Published: March 2010

Abstract
Citing recent case histories of lateral wells drilled in Canada, this paper describes the unique tools and planning methods employed In medium-radius lateral drilling. Included are operational and directional aspects related to BHA design and build-up rare (BUR).
Based on this review of field results obtained with medium radius methods in different locations and formations, the examples of problem-solving presented will illustrate that, in terms of the drilling system used, choice of hardware can determine the type of curve to be drilled as well as how it is planned and executed.

Introduction
During late 1987 and early 1988, three production wells were drilled in Canada in an effort to increase productivity from the oil-bearing formations through use of lateral drilling techniques.
The wells were drilled in three distinct areas, providing diversified data base upon which to base all evaluation or lateral drilling technology in different geological strata as well as to determine productivity changes in the varied target formations which included Swan Hilb and Jean Marie limestone, and Cardium sandstone.
While the three wells were drilled in different geographical area, target depth ranged only from l245 m to 2284 rn TVD. with lateral length~ from 450 m La 650 m measured depth planned.
To reach horizontal at their respective target depths, each well plan required an effective build-up rate (BUR) that would describe an are with a "medium-size" radius of 90 m to 95 m(1). Thus all were classified as "medium-radius" lateral wells as defined in common industry terminology and all used the same drilling technique's and equipment.

Background
For the first horizontal well in a given field, the most common medium-radius well profile is planned so that TVD and departure increase equally as the well bore However, the length of individual build sections (from 0 to 45 degrees and 45 to 90 degrees) may be adjusted to accommodate a given application by including an angle-holding tangent section in a "build-tangent-build" configuration (fig. 1).
In the case histories that follow, tangent section lengths were planned based on the proposed and minimum expected build rates. Any difference between proposed and "actual" BURs determines tangent length.
The difference in TVD at the end of an arc planned at 18 degree/30 m. but drilled at 15 degrees/30m, for example, determines how long (in measured depth) angle must be held at 45 degrees to ensure intersection of the target zone at the end of the final build (Fig 2).
For example, at a proposed BUR of 18 degrees/30 m, a radius of 95.5 m is described. At a minimum expected BUR of 15 degrees/30 m, the radius is 114.6 m, a difference of 19.1 m, which is reflected in a difference in TVD at the end of the arcs. A tangent of 27 m can be drilled at 45 degrees to compensate for the different BURs and the resulting difference in TVD. Proposed and actual build rate data for the three subject wells is presented in Table I.
Comments On "The Physical Chemistry Of The Hot Water Process", By K. Takamura And D. Wallace
Authors: Czarnecki Jan , Smith Russel 
Published: March 2010

Abstract
In the December 1988 issue of Tile Journal of Canadian Petroleum Technology, Koichi Takamura and Dean Wallace published a paper entitled "The physical chemistry of the hot water process"(1). The paper ‘describes a model for the hot water process based on the’ DLVO and lonizable Surface Group theories' 'that, according to the authors, can be used to maximize bitumen recovery from low grade oil sands.
On page 100 the authors claim that 'It is known* * that monodisperse panicles in an unstirred suspension will coagulate if the potential energy barrier to coagulation, Vscb, is less than 20 to 100 kT because the Brownian motion of the particle provides sufficient energy to overcome the repulsion between them. In a stirred reactor, hydrodynamic forces tend to drive the particles together and a higher energy barrier is required to keep them dispersed.' Both sentences above warrant a comment.In colloidal dispersion slow coagulation can be observed for the stability ratio W&lt; 104(2). W is defined as the ratio of rapid to slow coagulation rate constants (kr and ks respectively) and is related to the height and shape of the energy barrier with the following formula:Equation (Available In Full Paper)where the total interaction energy Φ is a function of the separation between the centres of the particles r, and 2R is the radius of ‘sphere of interaction’, which in the simplest model is assumed to be twice the radius of monodispersed, spherical particles R. A stability ratio of about 104 (which means that the coagulation rate is 10 000 times slower than it would have been if no energy barrier was present), for a typical barrier shape, corresponds to the maximum barrier height Φmax of about 15 kT. A barrier of 20 kT or more would thus characterize a stable system.For fine solid particles suspended in liquids, inertia effects can be neglected for Reynolds number (set on particle dimension) Re &lt; 1(3). Under typical industrial conditions, the Reynolds number based on the dimension of the vessel (typically of an order of metres) may be as high as 100 000. However, the Reynolds number based on the particle dimension (of an order of µm) is of about 0.1. The flow, as seen by particles of that size, fulfills the creeping flow conditions, and inertia effects for those particles can be neglected. Therefore, although stirring increases the number of collisions between the particles the hydrodynamic forces cannot ‘drive the particles together’ across the energy barrier. The barrier height necessary for stabilization of the system does not depend on whether the suspension of fines is agitated or not.
The barrier height of 400 kT units, assumed by the authors to be a critical value dividing stable from flocculating systems, is thus completely unrealistic. One can barely agree on a critical barrier height of 20 to 40 kT. Yet, even for a barrier of 40 kT, only one in 1017 particles has sufficiently high energy to pass across the barrier.
Producing And Processing Sour Gas In The 1990s
Authors: Hyne J.B. 
Published: March 2010

Introduction
Western Canada has a long successful record of sour natural gas production dating back to the early 1950s. Under the watchful eye of Alberta's provincial regulatory agency, the Oil and Gas Conservation Board and its successor, the Energy Resources Conservation Board (ERCB), many innovative techniques have been developed by the Canadian gas processing industry that both optimize production and recovery and protect the environment from unnecessary impact. What can we predict from this experience about technological developments in sour gas production in the 1990s?
Technological development is driven by a combination of the needs or society and the inventiveness of its members. New developments in sour gas technology in the 1990s will be governed by these driving forces in no less important a manner than any other field.
Historically the major societal need that has driven sour gas technology has been the need for the hydrocarbon component, primarily the methane gas. The "sour ", hydrogen sulphide has been, until more recently, viewed as a nuisance or worse. There is little doubt that the need for gaseous hydrocarbons both as fuels and petrochemical building blocks will continue to be an important factor in driving technological developments in the sour gas business, making resources available from reservoirs that were previously inaccessible or uneconomic. The days of the simple equation when market demand for the hydrocarbon was the overriding factor in pushing technology to produce more sour gas are gone. The equation is now much more complex and that complexity is being recognized in the directions that sour gas technology is taking as we enter the 1990s. There are the "benefits" that yield returns; but there are also costs that are becoming more and more important factors in the equation.

The Return Factors
Net production of hydrocarbon from sour gas development decreases as the hydrogen sulphide content increases. Nonetheless, the return from hydrocarbon sales will continue to be a dominant factor in the economics of most sour gas developments. The exception is super sour gas which will be discussed shortly.
Because methane is the most common hydrocarbon component of sour gas, the market for this commodity will continue to be a controlling factor. As a "clean" fuel, methane is not likely to be in less demand in the 1990s and at present comparative fuel prices, the market is almost certain to remain at least buoyant. New technological developments in methane end use are therefore likely to remain as an important factor in the economics that drive sour gas development. Very recent developments(1) in the catalytic conversion of methane to C2 and heavier organics, some without accompanying CO2, production, suggest exciting new possibilities for ready conversation of methane gas to liquid fuels and petrochemical feedstocks.
Methane, however, is not the sale hydrocarbon component of sour gas. The richer the gas stream is in higher hydrocarbons, the more attractive it will be as a petrochemical feedstock for new developments in this area.
Obituary S.R.L. (Stan) Harding 1912 - 1996
Authors: Kerr Aubrey 
Published: March 2010

Introduction
Born in 1912 to a family in straitened circumstances, Stan Harding grew up as a farm boy, spending summers with threshing crews. He recalled the stock market crash of 1929 when penurious pittances paid to the teachers were slashed. He also was a witness to the 1935 Regina riots.
Harding attended public school in Regina, not only excelling in his academic studies but also developing a special interest in gymnastics. He joined the YMCA and maintained an interest and association throughout his active life.
"... I went to Normal School in Regina ... and received a first class certificate to teach, in 1931." There then followed a number of assignments, his first one being a one-room school just east of Maple Creek for two years. He returned to Maple Creek where he taught for four more years, during which time he made many lifelong friendships.
Imperial Oil hired Stan upon graduation in 1941, and he reported to Dr. Sproule who put him in charge of catching samples on a seismic shot hole rig not far from his home town.
Stan returned to the University of Saskatchewan receiving his B.A. degree with honours in 1942. It was during this time that he married his school teacher friend, Jean Coutts.
"Dr. Mawdsley, who was at that time Head of the Geology Department, ... later Dean of Engineering ... always encouraged people to take geology through engineering (you could take your geology through arts or you could take it through engineering), and Dr. Mawdsley pushed people to take the geology through engineering. His reasoning was this: he said, ‘half of you fellows will never make geologists, so you might as well have an engineering degree.’" Mawdsley continued to advise Stan, ‘... well, you know, you are a pretty good student and you should continue.’ This involved going to McGill, the only school which could offer him an instructorship, under Dr. Tony Clark, plus a modest stipend.
Upon receiving his Master's Degree, Harding went on permanent staff, still under Sproule. He worked as a wellsite geologist for two years. At that time, Norcanols, a partly owned subsidiary of Imperial and a Calgary and Edmonton corporation, would drill a series of dry holes across the prairies.
By this time, Harding had become a father. He, his wife and baby lived in whatever accommodation was available, some of it quite primitive. On one occasion, he found living quarters in an abandoned stone house, a good part of a mile away from the rig, "and the company provided me with a truck ... " but when Cam Sproule found out about this "... he decided that transportation units were in short supply and that he could use my truck somewhere else-so he took my truck away ... there was a surveyor by the name of J.A. Armstrong who needed a unit, and J.A. Armstrong (later to be Imperial Oil's president) got my truck!" So Stan ended up walking to work every day.
Evolution of Production Practice And Reservoir Management of the Winter Field
Authors: El-Sayed S. , Beckie W. 
Published: March 2010

Abstract
Actual production data of Winter Field were examined for production rates, oil cut, cumulative oil produced and reserves per well in relation to well length. The log oil cut vs. cumulative oil production per well of groups of wells plots showed that the reserves at a 2% oil cut was the same despite the different lengths of these wells. Published data were next examined to establish the relationship between well length and reserves. It is obvious that the relation between reserves as a function of well length is not a linear relationship for the entire well length examined. This relation shows that as the well length increases from 200 m to roughly 500 m there is a linear increase in reserves. The slope of the line is less than one (0.7); as the length increases beyond 600 m there is very little increase in the reserves. This could explain why the Winter wells all have the same reserves. These groups of wells varied in length from 574 m to 1,110 m; that is, they are all in the length range (greater than 500 m) that gives the maximum reserves(1).
In order to verify this conclusion and utilize it to increase the reserve from existing and future wells a series of well workovers and treatment programs were carried out. Newly drilled wells were completed in such a way as to use the conclusions and recommendations of these programs.

Introduction
The Winter field (Figure 1) has been developed utilizing horizontal wells to produce heavy oil (13.7 API oil of 2,800 – 3,800 cp. viscosity) in a 12 m thick Cumming Sand underlain by a very strong aquifer. The oil cut vs. oil cum. per well plots for each phase (wells drilled in a specific year) are shown in Figure 2. It is obvious that the reserves per well at an economic oil cut of 2% are essentially the same for the different phases. It is interesting to notice that the average well length for the different phases ranges from 574 m to 1,111 m. Data for over 250 horizontal wells producing oil over water reservoir in Saskatchewan published in SEM publication were analysed and the reserves as a function of length are shown in Figure 3. This figure illustrates the non-linear nature of the relationship between reserves and well length. For example a well of 200 – 300 m length has a reserves of 9,000 m3 while a well of 1,000 – 1,100 m has a reserves of 15,000 m3; rather than the 30,000 – 40,000 m3 expected in a linear correlation. Detailed analysis of every well in the Winter Field was carried to identify potential reasons for better or worse performance. A series of water shut-off treatments and workovers were carried out. External casing packers were utilized for formation isolation and proved to be effective. Finally, the information gained from all of the above is being tested in some of the 1995 drilling program through a new completion practice targeting reserves maximization with minimum effect of initial rate.