Abstract The current available equipment used in the laboratory to measure permeability of the core samples is very limited. This is because permeability is measured only in one dimension and the faces of the core samples are damaged due to the grain repositioning during sample cutting. The only way to measure permeability is by using a nondamaged sample by chipping it off from the rock. This situation occurs only with drilling cutting samples. New laboratory equipment was designed to measure permeability of the cutting samples. A probe is used in this equipment which is easy to change to accommodate different cutting sample sizes. While using any cutting samples, three different perpendicular points are used and their permeability values measured. When two permeability readings are identical, they quantify the plane permeability. This method of permeability measurement is considered more realistic because: most of the cutting faces are minimally damaged. This equipment is very simple to use, operate and maintain in the laboratory. The equipment is light and portable and can also be used in the field. Introduction The current permeameters used in the oil industry to measure rock permeability require core samples of certain length and diameter. For example, the gas/liquid permeameter require core samples of 1.5 × 1.0 - core sample size. During cutting in the laboratory most part of the core sample is invaded by the water used to cut the sample. The presence of water and core cutters causes certain damage to the faces of the core samples. Sharpening the inlets and outlets of the core sample using core cutter cause repositioning of the gram. This occurs while a gram is removed during cutting and repressed or positioned as water flows over the edge. This gram repositioning causes the reduction of permeability. On the other hand, if the water used to cut the core sample is incompatible with the clay stability in the core, this clay may swell causing permeability changes. Permeameters that use pressure decay on a long core sample have the same problems('). In addition, this type of equipment can measure permeability in two directions only. As a result, permeability of the core samples does not represent the real rock permeability. Experience showed that core samples permeability is in the range 6570% of the real permeability. This is based on comparing the measured permeability to the calculated permeability from logging data. The Core Measurement System (CSM) has the same disadvantage. Since core samples have high level of heterogeneity, either an average permeability can be calculated or certain points should be chosen along the core sample(2l. The rock heterogeneity is a good reason for getting permeability from cutting samples since they are available. Permeability can also be calculated from well testing data, however despite being more accurate, this method is quite expensive. Another way to measure permeability is by using formation tester from service companies. However, in the vicinity of packer in the high permeability rock the drawdown pressure is too small to be accurate.

Abstract The present study consists of an experimental investigation of dispersion in inhomogeneous layered, isotropic porous media. Thanks to an in situ method of measuring electrical conductivity, we have studied two layered models. We examine four different layouts. The first sample has three layers of different permeabilities. The second has only two layers. Furthermore. two models with layers oriented perpendicular to the flow are considered. Besides normal "gaussian" dispersion, clear cut anomalies were observed. The experimental breakthrough curves are skewed as a consequence of tracer tailing. Tailed breakthrough curves are known from displacement in cores with local heterogeneity. Good agreement has been obtained between the experimental results and the semiphenomenological model of Coats Smith. Thus~ the mechanism involved in this anomalous dispersion is not trapping in the so-called dead end pores, but rather is due to different residence times because of permeability difference. Introduction The mixing of a tracer during flow through a porous medium involves the interplay between the two basic phenomena of dispersion, namely, molecular diffusion and mechanical (geometrical) dispersion. If two miscible fluids are in mutual contact. initially with a shaped interface, they will diffuse into one another because of random molecular motion according to the diffusion law of Fick 1 :: Equation (1) (Available in full paper) To account for the tortuous path of a porous medium, equation (I) was modified by Klinkenberg 2 , who used the analogy with electrical conductivity, thus: Equation (2) (Available in full paper) Do thereby corresponds to the bulk molecular diffusion coefficient for the fluid multiplied by the geometric factor (F Ø). The formation factor is F= σ o / σ, were σ denotes the electrical conductivity of a rock saturated with a fluid of conductivity σ O Ø. is the porosity of the rock. Molecular Diffusion is the dominant factor at extremely low or zero flow rate. At a higher flow rates, fluid flow plays a key role: there is a competition between the dispersive effect of the velocity gradients in the flow, and the various processes that homogenize the tracer (diffusion and transverse dispersion) across the porous media. The dimensionless Peelet number, which is the ratio of convective velocity U to the average velocity of molecular diffusion over a distance I characterizes this competition. Thus: Equation (3) (Available in full paper) This further mixing. which occurs in the direction of flow (axial) and perpendicular to it (transversal) is due to the combined action of three boundary effects: - hydrodynamic dispersion: This mechanism was first described by Taylor 3 ; the velocity is zero on the matrix surface. which creates a velocity gradient in the fluid phase. The characteristic time of homogenization - τ - (a 2 /D) - is associated with the molecular diffusion of the tracer across the width of the pore. Aris 4 found the following for low velocities, where molecular diffusion is dominant: Equation (4) (Available in full paper) - geometric dispersion:

Abstract An extensive interwell tracer program was conducted at the Bone Creek Unit between 1984 and 1986. The objectives were to obtain insights into the flow distribution and, to infer clues regarding potential improvements to the waterflood. Detailed interpretations of tracer returns helped in refining reservoir description in terms of lateral as well as vertical heterogeneities. These additional details were independently verified by a history match of the unit's performance and, were by and large consistent with the cross-section fence diagrams of the pay zone prepared from log and core data. Based upon the composite knowledge thus obtained, a better understanding of sweep patterns around different injectors resulted. The tracer program led to certain changes in injection-production patterns. Four infil1 wells were drilled. Several additional infill locations were identified. Many parts of the unit, such as the northwestern portion, experienced poor sweep and poor oil recovery. These were caused, in part, by reservoir heterogeneities. With the improved knowledge of these heterogeneities, appropriate enhanced oil recovery schemes for the unit were explored. Similarly, a better understanding of the performance of the waterflood provided clues to its possible improvement. Introduction The Bone Creek/Ins tow pool is a Middle Jurassic, Upper Shaunavon tidal channel deposit located in the Southwestern part of Saskatchewan (Figure 1). It is situated along the Rapdan-Dollard- Gull Lake oilfield trend, an ancient shoreline sequence of sandstone deposits. The pool is approximately eight km long and three km wide, crending in a Northwest-Southeast direction (Figure 2). Relevant pool data are summarized in Table 1. The pay zone can be divided into two distinct litho-facies, a predominant calcareous sandstone with an average permeability of five millidarcies, and an interbedded quartzose sand with an average permeability of about a hundred millidarcies. Based upon the log and core data, a detailed fence diagram of the pool has been prepared (Figure 3). Because of the variable and discontinuous nature of the quartzose sand members, their continuity from one well to the next is difficult to ascertain. (The percentage of total pay interval belonging to the quartzose members is mapped in Figure 4). The pool has a low primary recovery (5%) because of the existence of a medium gravity crude oil (914 kg/m 3 or, 24 degrees API) discovered initiially at undersaturated conditions. A peripheral waterflood, initiated in 1960 is projected to recover an additional l7% oil-in place (Figures 5 and 6). The. feasibility of any improvement (workovers, altering operation, infill drilling and/or chemical flooding) depends upon a more complete knowledge of the lateral continuity and variability of quartzose sand members. Three members are considered to be the main conduits for accepting injection as well as for contributing the bulk of production. Saskoil, as the operator of the Bone Creek Unit, conducted an interwell tracer program on the pool between 1984 and 1966. Eleven injection wells received radio-active tracer slugs with the injected water (Table 2. and Figure 7).

Abstract The characterization of reservoir rock, using Computer Assisted Tomography (CAT) with x-rays has been an objective of increasing popularity in the petroleum industry. In the present study, a medical x-ray CAT scanner was used for the study of core material from the "BIT member of the Clearwater Formation of the Lower Cretaceous Mannville Group in the Cold Lake area. Two pieces of core, each approximately 0.3 m long, were scanned at 0.01m intervals at a resolution of 0.00075m × 0.00075m × 0.005m. The raw CAT scan data were analysed using a postprocessing computer package developed in our laboratories at NOVA Husky Research. This analysis gives a detailed picture of the various heterogeneities within each core section including cracks, shale barriers and clay clasts, and also allows determination of core properties such as bulk density and porosity. Bulk densities determined from the CAT scan data are in good agreement with direct measurements obtained from several plugs taken from the core. The CAT scanning of the core successfully identified the locations for good plug selection. In addition, various types of heterogeneities were mapped in three dimensions. Significant core damage was observed which is atcributed to the coring and freezing processes. This paper presents the methodology of the scanning and the subsequent data analysis. Introduction Computer Assisted Tomography (CAT) x-ray scanners have become a useful tool for the petroleum scientist and engineer. A detailed literature survey has recently been prepared by Kantzas (1989) while various applications are described in a variety of papers (e.g. Wellington and Vinegar (1987), Kantzas et.al (1989). of particular relevance to this work are various papers describing applications to heavy oil recovery (Fransham and Jelen (1986), Sedgwick and Miles-Dixon (1987) J Cuthiell and Sedgwick (1988). The quantitative representation of core properties has been the focus of a lot of our work recently. The effort focused on consolidated media and particularly in the Alberta dolomitic reservoirs. In this paper we address the potential of using the same technique for unconsolidated media. The CAT scanner can measure bulk density and effective atomic number directly by doing the so-called dual scanning i. e. one scan at an energy which is predominantly producing Compton scattering phenomena and one energy where photoelectric absorption is dominant. Fluid saturations can be measured in a core if the core is scanned while saturated and While dry at different energy levels and, if the fluids are scanned separately (Kantzas, 1988). This is very important when flow processes are monitored (e.g. Fransham and Jelen (1986), Cuthiell and Sedgwick (1988), Wellington and Vinegar (1987), Kanezas (1988)). In the. case of heavy oil unconsolidated sands, the core is drilled and frozen immediately in an effort to preserye it at conditions as close to the reservoir as possible. When the core reaches the core lab, plugs are taken at different intervals and core analysis is commencing. The recovery of unconsolidated sand during coring involves using a rubber or plastic sleeve core barrel.

Abstract Heavy oil reservoirs of Saskatchewan are characterized by thin pay, shaley sand, heterogeneity, low productivity and bottom water. Thermal recovery processes are not expected to be economically feasible for reservoirs containing approximately eighty percent of the heavy all in the province. The carbon dioxide immiscible flooding process 15 considered to be the most promising among the non-thermal recovery methods for these reservoirs. This paper presents a survey of the recent laboratory and field studies of the heavy oil-carbon dioxide immiscible process and the results obtained from phase behavior and core displacement experiments. Viscosity, density, bubble point pressure, Gas-oil ratio (GOR) and swelling factor for the reconstituted reservoir fluids and CO 2 -saturated wellhead oil and reservoir fluid were measured at 28 °C and pressures up to 8.27 MPa. A forty-fivefold reduction in Viscosity and a 16% Increase In the swelling factor were observed in the heavy oil-CO 2 system. Carbon dioxide once dissolved in the heavy oil at a high pressure remains in solution even when the pressure is reduced. Waterflooding of the oil-saturated core produced 31.5 to 46.2% initial oil-In-place (IOIP). The Incremental recovery from the CO 2 Injection Into the water flooded core was between 12.7 and 38.6% residual oil-in-place (ROIP) in the water-alternating gas (WAG) mode and between 23.1 and 33.2% ROIP for the slug process. The total recovery appeared to level off at 60% IOIP. The CO 2 injection into the core at the initial oil saturation recovered 29.9% IOIP in the WAG mode and 41.6% IOIP for a slug process where CO 2 was allowed to soak for 69 h. There appears to be considerable merit in soaking with CO 2 prior to water injection. Introduction Saskatchewan has an extensive gesture of heavy all. The proven resource 1.0 × 10 9 m 3 and the probable oil-in-place 3.4x10 9 m 3 . 1 The heavy all reservoirs of Saskatchewan ate characterized by thin pay, shaley sand, heterogeneity, low productivity and bottom water. Fifty-five percent of the Initial heavy oil-in-place is contained in reservoirs less than 3 m thick and ninety-five percent in less than 7 m thick. 2 Primary and secondary methods together recover less than ten percent of the initial oil-In-place. The development of appropriate recovery techniques specific to Saskatchewan reservoirs is necessary If the full potential of this resource is to be realized. Saskatchewan's heavy oil enhanced recovery projects have centered around steam injection and in-situ combustion. While steam Injection has been very successful, it is not expected to be economically feasible for those reservoirs which contain approximately eighty percent of the heavy oil. 3,4 In-situ combustion, although applicable to thin reservoirs, has been and marginally successful thus far. Recovery of heavy oil using carbon dioxide immiscible flooding is considered to be the most promising among the non-thermal EOR processes, particularly for those reservoirs having such undesirable geology as found in Saskatchewan. 4–6 Since 1982 the number of carbon immiscible projects in the United States has grown from zero to eighteen. 3