Brij B. Maini

Measurement of gas diffusivity in heavy oils

Abstract Molecular diffusion of gases in oil plays a role in several heavy oil recovery processes. In solution gas drive, the gas diffusion coefficient has a direct impact on the amount of gas that is released and the level of supersaturation that exists during pressure depletion. In the Vapex process, molecular diffusion controls the rate at which the solvent vapour is absorbed by the oil. Molecular diffusion is also important in supercritical fluid extraction of heavy oils and in recovery of residual oil by miscible displacement. Unfortunately experimental data on gas diffusion coefficient in heavy oils are relatively scarce due to the tedious nature of diffusivity measurements. The main objective of this work was to develop a simple experimental technique for measuring gas diffusion coefficients in heavy oils. Diffusion coefficients of carbon dioxide and methane were measured by measuring the rate of gas absorption in a high-pressure windowed cell. The diffusion equation, coupled with the gas material balance equation, was used to history match the gas absorption data using the diffusion coefficient as an adjustable parameter. The diffusion coefficients calculated by this history match technique are compared with the reported values of diffusion coefficients in similar systems.

Experimental investigation of hydrate formation behaviour of a natural gas bubble in a simulated deep sea environment

Abstract A vertically flowing, closed circuit, high pressure water tunnel was designed and constructed for holding individual gas bubbles stationary against an opposing flow for detailed observations. Hydrate formation behavior of natural gas bubbles was studied at constant pressure as well as under conditions of controlled decompression designed to simulate buoyant rise of the bubble. A bubble of simulated natural gas suspended in 3°C salt water formed hydrates when the pressure was 4826 kPa or higher. The simulated decompression accompanying buoyant rise had very little effect on hydrate formation behavior of a bubble starting from a pressure of 5516 kPa or above. At lower starting pressures, a slight increase in the reaction rate was detected in the initial stages of a run. The conversion of the simulated natural gas to hydrates was complete in runs starting from a pressure of 4826 kPa or above.

Phase Behaviour and Physical Property Measurements for VAPEX Solvents: Part I. Propane and Athabasca Bitumen

The saturation pressure and solubility of propane in Athabasca bitumen, as well as the liquid phase densities and viscosities, were measured for temperatures from 10 to 50°C. Equilibration proved challenging for this fluid mixture and required some experimental modifications that are discussed. Only liquid and liquid-vapour phase regions were observed at propane contents below 20 wt%. A second liquid phase appeared to have formed at higher propane contents. The saturation pressures, where only a single dense phase formed, ranged from 600 to 1,600 kPa and these were fitted with a modification to Raoults law. Viscosities less than 210 mPa.s were obtained at a propane content of 15.6 wt%. All of the viscosity data of the liquid phase were predicted from the propane and bitumen viscosities using the Lobe mixing rule.

Foamy-Oil Flow

Foamy-oil flow is a non-Darcy form of two-phase flow of gas and oil encountered in many Canadian and Venezuelan heavy-oil reservoirs during production under solution-gas drive. Unlike normal two-phase flow, which requires a fluid phase to become continuous before it can flow, it involves flow of dispersed gas bubbles. This paper is aimed at acquainting the readers with this type of flow and its role in heavy-oil production. The paper starts with a discussion of what the term foamy-oil flow means and how it evolved. Then a brief review of the Canadian field practices is presented. This is followed by a discussion of the pore-scale mechanisms involved and the interplay between capillary and viscous forces. A discussion of the strengths and weaknesses of various mathematical models proposed for numerical simulation of this type of flow is also included. The paper ends with a brief discussion of issues that remain unresolved.

Phase Behaviour and Physical Property Measurements for VAPEX Solvents: Part II. Propane, Carbon Dioxide and Athabasca Bitumen

The solubility of pure carbon dioxide in Athabasca bitumen was measured and compared with the literature data. Multiple liquid phases were observed at carbon dioxide contents above approximately 12 wt%. A correlation based on Henrys law was found to fit the saturation pressures at carbon dioxide contents below 12 wt%. The saturation pressure and solubility of carbon dioxide and propane in Athabasca bitumen, as well as the liquid phase densities and viscosities, were measured for three ternary mixtures at temperatures from 10 to 25°C. Two liquid phases (carbon dioxide-rich and bitumen-rich) were observed at 13 wt% carbon dioxide and 19 wt% propane. Only liquid and vapour-liquid regions were observed for the other two mixtures (13.5 wt% propane and 11.0 wt% carbon dioxide; 24.0 wt% propane and 6.2 wt% carbon dioxide). The saturation pressures for the latter mixtures were predicted using the correlation for the carbon dioxide partial pressure and a previously developed correlation for the propane partial pressure. The mixture viscosities were predicted with the Lobe mixing rule.

Measurements and Modelling of Phase Behaviour and Viscosity of a Heavy Oil/Butane System

Solvent-based heavy oil recovery methods are of interest as environmentally friendly alternatives for thermal techniques. The phase behaviour data from a heavy oil/solvent system are important information required for feasibility studies and numerical simulation of such processes. The scarcity of experimental data in the literature is a challenge in modelling of solvent involving processes. The variety of the solvent/oil mixtures, which are being evaluated within ongoing researches such as the VAPEX (vapour extraction of heavy oil) process, requires accurate description of the systems pressure, volume and temperature (PVT) properties. In this study, an experimental setup was designed to perform a series of PVT experiments and viscosity measurements. The results of the PVT tests conducted with the Frog Lake heavy oil and butane as a solvent are presented. The same oil/solvent pair was used in the VAPEX experiments previously reported by the authors (1,2) . The measurements include the solvent solubility in the oil, mixture density and mixture viscosity at different saturation pressures. To simulate the phase behaviour of the system, an equation of state (EOS) was tuned using the measured experimental data and a phase behaviour package (WINPROP). The predicted densities and saturation pressures by the EOS are in very good agreement with the experimental data. A mixing viscosity correlation was also tuned with the measured data and found to be representative for describing the viscosity of the system. The viscosity data were compared with the predictions of several other available correlations, and it was shown that Shus model (3) reproduces acceptable data for reservoir simulation purposes.

Temperature Effects From the Conditioning and Flotation of Bitumen From Oil Sands in Terms of Oil Recovery and Physical Properties

Batch extraction tests show that, for Athabasca oil sands, the water-based conditioning/flotation process can be adjusted from 80 to 50 °C conditions without substantial changes in optimal process aid addition level or primary oil recovery obtained. When the process temperature is further reduced to 25 °C however, an order of magnitude reduction in primary oil recovery is obtained, suggesting that one or more key process variables have undergone a substantial change. Our studies with process additives suggest that several key physical properties undergo major changes, including bitumen viscosity, interfacial tension, and interfacial charge. If these are addressed then comparable optimum primary oil recoveries can be achieved under all of 25, 50, or 80 °C conditions. This is a significant result in terms of identifying the key mechanism(s) by which good primary froth recovery can be achieved. It is shown that the interfacial property changes in particular are consistent with the expected thermodynamic conditions necessary for efficient bitumen separation and flotation.

Role of Asphaltene Precipitation in VAPEX Process

VAPEX (vapour extraction) is an oil recovery process, in which heavy oil or bitumen is mobilized by injection of a low molecular weight hydrocarbon solvent and is drained by gravity to a horizontal production well. It has attracted considerable attention because of its potential applicability to problematic reservoirs and the potential for in-situ upgrading of heavy oil during the process. Oil drainage rate under VAPEX is controlled by the viscosity of solvent diluted oil and can be affected substantially by deasphalting. In-situ de-asphalting can be advantageous because it reduces the oil viscosity and leads to production of upgraded oil. However, the precipitated asphaltenes can also plug the pores of the formation and cause severe damage to the permeability. The objective of the current work was to determine whether the beneficial effects of asphaltene precipitation would outweigh any formation damage. The effects of in-situ precipitation and deposition of asphaltenes on the rate of oil drainage and the quality of the produced oil under different operating conditions were experimentally evaluated. The experiments were conducted in a physical model, packed with 140 - 200 mesh sand, and propane was used as the solvent. The quality of the produced oil samples was evaluated through the SARA technique and viscosity measurements. The experimental results show that the oil produced at higher injection pressures was substantially upgraded, but the viscosity reduction by asphaltene precipitation did not lead to higher production rates. The effect of viscosity reduction was negated by the accompanying damage to formation permeability. The huff and puff injection of toluene into the production well, to remove damage from the near well zone, was tried but proved to be ineffective. It led to production of oil with higher asphaltene content with no improvement in the rate of oil production compared to the lower pressure operation without asphaltene precipitation. However, co-injection of toluene with propane was successful in increasing the rate of production and the extent of upgrading obtained was encouraging.

Fluid Movement in the SAGD Process : A Review of the Dover Project

The fundamentals of Steam Assisted Gravity Drainage (SAGD) steam chamber development are now well understood through Butlers analytical models, as well as extensive field and laboratory testing. However, as the industry continues to extend SAGD to new reservoirs and look towards SAGD wind-down at the end life of projects, it is important that we recognize the value of not only understanding the steam chamber, but also of the movement of fluid in the reservoir. The Dover SAGD Pilot is the most mature pilot of its kind in the world. A study of this project has been undertaken in an attempt to understand the behaviour of the fluid within and in front of the steam chamber. The economics of SAGD are significantly impacted by the cost of generating steam. At roughly 283.17 m 3 /bbl (1 mcf/bbl) of bitumen produced for a steam-oil ratio (SOR) in the range of 2.3 to 2.5 m 3 /m 3 , natural gas is the single largest operating cost in a SAGD project. Water movement within the reservoir can impact the natural gas consumption, whereas warm steam condensate not reproduced must be replaced in the process by colder make-up water decreasing the heat efficiency of the steam generation. Further, where water loss to the reservoir is high, the SOR may be negatively impacted. On the 20th anniversary of the initiation of the Dover Pilot, the cold water injection test performed prior to any thermal operations taking place is revisited here. Understanding the transmissibility of water in the reservoir is key to choosing the optimal operating pressures and maximizing the value of a project. It has been widely published (1,2) that the injection of non-condensable gas (NCG) into SAGD chambers will result in the accumulation of the NCG at the top of the chamber, cooling the chamber. The lower temperatures within the chamber cause the viscosity of the bitumen to increase, thereby reducing the bitumen production rate. This has been suggested as a method of winding down steam chambers as they reach their economic producing limits (3-5) . From April 1998 to May 2002, NGC was injected with steam at the Dover Pilot. The gas volume injected was triple the volume of the produced bitumen over that time. The SAGD chambers did not behave as predicted. The bitumen production rate did not fall off any more than would be expected from a mature steam chamber and live steam was still detectable through the thermocouples within the steam chamber. Furthermore, an increased overall recovery was observed, most likely from gas assistance in the production of previously inaccessible reserves. The simulation model developed to describe the behaviour of NCG in the reservoir, as well as further observations regarding this behavoiur, are discussed.

Steam Flooding of Naturally Fractured Reservoirs: Basic Concepts and Recovery Mechanisms

A review of important issues in steam injection in naturally fractured reservoirs (NFRs) is presented. The effect of temperature on physical properties of crude oils and rocks and the thermochemical alteration of crude oil are discussed. The recovery of oil from NFRs can be modelled as a two step process: first the oil is expelled from the matrix blocks through mechanisms that impose a pressure gradient within each matrix block and then it is swept through the fracture network to a production well by mechanisms that impose a pressure gradient within the fracture network. The recovery mechanisms associated with steam injection in NFRs and their characteristic times are presented. The most important recovery mechanism in matrix blocks is differential thermal expansion between oil and the matrix pore volume and the strongest mechanism in fracture network is the reduction of viscosity ratio (μ 0 /μ w ). The matrix oil recovery mechanisms are relatively independent of oil gravity, making steam an equally attractive recovery process in fractured light and heavy oil reservoirs. The mechanism and impact of CO 2 generation during steam injection in carbonate reservoirs are discussed. The rate of CO 2 generation is controlled by the rate of heat conduction from fracture into the matrix. For a specific reservoir the rate of heat conduction is a function of temperature and injection rate of steam and these can be optimized to make use of the in situ generated CO 2 .