A novel approach with fewer technical and analytic limitations in liquid solvent-bitumen diffusion studies is used in this article. The Taylor dispersion technique was selected for its convenient short run time experiments and reliable data analysis to find mutual diffusion coefficients in a hexane 1 bitumen mixture. For the first time, the infinite-dilution molecular diffusion coefficients of bitumen in hexane were measured in both the presence and relative absence of asphaltene particles in the solution at atmospheric pressure and temperatures of 303.15, 310.15, and 317.15 K. The polydisperse nature of bitumen was clearly revealed. Results were compared with common predictive tools. Also, the asphaltene surface charge in the hexane precipitating solvent was demonstrated. Through concentration dependency investigations at atmospheric pressure and 303.15 K, it was determined that the mutual diffusion coefficients monotonically decrease as the viscosity of mixture increases within the studied 0-34% volumetric concentration of bitumen. The Taylor dispersion technique shows great potential for diffusion studies of liquid solvent-bitumen systems.

Information about diffusion in solvent þ bitumen/heavy oil mixtures is useful for the design of solvent-assisted recovery processes as a key parameter in reservoir simulation models. Reliable mutual diffusion coefficient measurements for these systems present significant challenges. In this article, experimental techniques for the study of diffusion in liquid solvent þ bitumen/heavy oil systems are critically reviewed, and the strengths and weaknesses of each method are highlighted. Despite considerable progress in this area with the application of state-of-the-art techniques, such as X-ray computer-assisted tomography measurements, additional work is needed to measure the composition profiles in these opaque systems more precisely and to analyse the measured concentration profiles more conveniently.

Gas or fluid ingress into the cement channel and then up to the surface through the surface casing annulus is called Surface Casing Vent Flow (SCVF), which causes Sustained Annulus Pressure (SAP) as a common occurrence in the petroleum industry. Gas may also migrate to the surface outside the outermost casing string, which is often referred to as external Gas Migration (GM) or seepage. In some countries with shallow coal reserves, gas migration sometimes occurs in association with coalbed gas (CBG) development. Dewatering the coal seams or lowered water levels in coal, whether induced by drought or by domestic aquifer pumping, can result in the release of methane and other natural gases in coal (NGC). Hydrocarbon gases released into the atmosphere is an environmental concern. More importantly, leaking fluids may contaminate subsurface fresh-water reservoirs, resulting in a major catastrophe for the environment and human population. According to the latest statistics, 6% of almost 270 000 operating and idle wells analysed in Alberta were found to contain leaks, 5.5% of them having SCVF and 0.5% gas migration [2]. Operators are bound by the Alberta Energy Regulator (AER) to identify and eliminate leaks and perform remedial operations as outlined in AER's rules and directives. Even if a well is to be abandoned, the operators must precisely identify the location of the leak and its source to perform a successful plug-and-abandonment (P&A) operation. P&A activities are non-revenue generating activities. The right diagnostic technology is critical for correct leak source identification to eliminate the costs associated with numerous unsuccessful attempts. The technique of Spectral Noise Logging (SNL) coupled with High Precision Temperature (HPT) Logging have extensively benefited oil industry outside Canada in accurately identifying fluid flow behind multiple casing pipe barriers and in locating leaks and their sources [3–5]. This paper describes two case histories for eight wells in the Western Canadian Sedimentary Basin (WCSB) in South Alberta region for two clients, where application of these techniques enabled gas leak source identification in a series of wells suffering from minute leak rates and also helped to discover some regional lateral flows and cross-flows.

Production decline analysis is the analysis of past trends of declining production performance to estimate hydrocarbon in place and determination of reservoir parameters. In this paper a case study on an oil field is carried out by performing decline curve analysis to see whether conventional decline models developed for vertical wells are also suitable for horizontal wells. Results demonstrated that Blasingame's radial model yields best results for permeability and skin while material balance analysis estimates best values for oil in place and drainage area. Also, it demonstrates power and simplicity of these methods in the absence of well test data.

Water injection is one of the main oil recovery techniques, which usually associated with problematic and challenging formation damage concerns including mineral scale deposition, organic scale, clay swelling, particle invasion, fine migration and microbial damage. These concerns usually significantly affect the performance of water injection scenarios by reduction of production rate and therefore ultimate recovery. In this work, mineral scale deposition phenomenon due to sea water injection and its influence on productivity loss and the reservoir performance of an Iranian offshore carbonate oil reservoir have been investigated. This filed has been producing by water injection since 1985. During these years the field has facing several formation damages mechanisms especially mineral scale deposition. For this purpose, a simulation study using solid deposition module of Eclipse 100 (v. 2006) has been conducted to simulate various phenomena occurring in the reservoir due to water injection, which undermines the oil production rate. As input of the simulation, the actual amount and concentrations of scale formed due to mixing of various portions of formation and injected sea waters and the productivity index reduction due to injection of different water mixtures are needed. These data must be experimentally measured in an actual bulk and core media for the studied reservoir. Comprehensive laboratory studies have been, therefore, conducted to obtain the simulation required information. These data have been incorporated into the simulation model to evaluate the scale deposition effects. The simulator enables to model the mixing zone, mineral scales precipitation, reservoir performance and productivity index reduction due to sea water injection process. The results show that the production loss due to scale deposition can be predicted/ simulated reliably by using the applied methodology and appropriate required experimental works. Introduction Water injection is a common IOR method, usually applied in offshore oil fields for the purpose of pressure maintenance and enhanced oil recovery. During secondary and tertiary recovery by this method, reductions of permeability have been observed in many reservoirs. Several reasons are recognized as possibly contributing to this problem such as mineral scale deposition, solid invasion, clay swelling and rock-fluid incompatibility. Mineral scale deposition is the main factor discussed in this paper. Mineral scaling is the deposition process of scales from aqueous solutions of minerals (i.e., brines) when they become supersaturated due to the alteration of the state of their thermodynamic and chemical equilibrium. Supersaturation can be generated in an aqueous phase by changing the temperature and pressure or by mixing two incompatible aqueous solutions. Mineral scaling can occur in tubing and near wellbore region of both production and injection wells.1 The significant components of most oil field scale deposits are Calcium Carbonate (CaCO3), Calcium Sulphate (CaSO4), Barium Sulphate (BaSO4) and Strontium Sulphate (SrSO4). Oil field deposits are usually a mixture of one or more of the inorganic compounds plus corrosion products, Congealed oil, Paraffin, Silica and other impurities. Table 1 demonstrates the most common oil field scales with their primary variables.1, 2, 3 Calcium Carbonate scale generally causes sharp reductions in pressure such as that exist between the formation and the wellbore and across any constriction in the producing system, e.g. chocks and safety valves. The reduction in pressure liberates CO2 in gas phase leaving the solution more concentrated in Calcium Carbonate. The various form of Calcium Sulphate i.e. gypsum, anhydrate and hemihydrate can be formed due to increase in temperature. 2