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In the process of natural energy depletion, foamy oil is characterized of low production Gas Oil Ratio, high oil viscosity, high daily production rate and high primary recovery factor. The stability of the foam turns out to be the prevailing factor that governs the life of the ‘foamy oil’. To enumerate the main factors affecting the stability of the foam, a high-temperature–high-pressure visualized experiment model for foamy oil stability test was developed. A serial of experiments was conducted to evaluate the performance of the foam stability. The effects of oil viscosity, height of the oil column, dissolved gas content and dispersed gas were investigated and recorded. These experiments were conducted using a Hele-Shaw, a high pressure cell. The volume of foamy oil produced, either by a step reduction in pressure or by a gradual (linear) reduction in pressure, and its subsequent decay was observed, visually. The experimental results show that foamy oil stability increases with higher oil viscosity, higher oil column, higher dissolved gas content and higher pressure decline rate. Asphaltene content was not observed to increase the foamy oil stability significantly. The results also show that the foam quality of foamy oils is much lower than aqueous foams.

Foamy oil flow occurs in primary depletion of heavy oil reservoirs as has been demonstrated in many laboratory experiments. It is thought to be an important recovery mechanism in several heavy oil reservoirs in Canada and Venezuela, which have shown higher recovery factors compared to what is expected from the normal solution gas drive theory. This work investigates the effects of several process parameters on oil production rate and recovery factor in foamy solution gas drive. The parameters examined included gas-oil-ratio (GOR), saturation pressure, the rate of pressure depletion and the drawdown pressure. GOR was varied independent of saturation pressure by using different gases, namely, methane, ethane and carbon-dioxide. Each foamy oil system was fully characterized by measuring gas oil ratio, oil compressibility, live oil viscosity, surface tension and foam stability. A total of 10 solution gas drive experiments were carried out in 2-meter long sand-pack equipped with several intermediate pressure taps using different solution gases and varying pressure decline rates. The results show that the foamy solution gas drive performance is affected by solution gas-oil-ratio in a counterintuitive manner. The oil recovery decreased with increasing gas oil ratio at fixed saturation pressure. At the same rate of pressure depletion, higher oil recovery was obtained with methane saturated oil than with carbon dioxide saturated oil. Ethane, which had the highest solubility, provided the lowest recovery factors. It was also found that the oil recovery factor did not decrease significantly when the saturation pressure was decreased from 3,500 kPa to 2,100 kPa. An analysis of all 10 depletion tests revealed that the most important factor that affects the oil recovery performance was the drawdown pressure, which was defined as the difference between the average sand-pack pressure and the production port pressure. Results obtained with different solution gases and widely varying depletion rates fell on the same trend line when the final recovery factor was plotted against the average drawdown pressure applied during the depletion.

Vertical or straight hole drilling that usually has less than 30 degree still is utilized to drilling operations in conventional and even in unconventional resources in nowadays worldwide for increasing recovery i.e. higher rate of penetration where there are kind of challenges that demand investigation of this type of drilling. One key challenge is efficient hole cleaning or cuttings removal which can lead to issues related to hole problems and consequently problems such as high over pull margins and stuck pipe may occur. Furthermore, inappropriate use of drilling fluid properties at different stages of drilling operation causes the hole to collapse due the accumulation of cuttings in the annulus as well as at the wellbore. The present study introduces an analytical and a numerical model for a vertical well that can be used to optimize drilling operations. The transport velocity i.e. the ration of the annular velocity and slip velocity is so vital in hole cleaning. Inefficient hole cleaning may lead to problems such as, slow drilling rates which increase drilling time and costs. For a vertical well, as addressed in the literature, the proper hole cleaning is basically dependent on drilling hydraulics or mud rheology liked rilling fluid density, viscosity and thixotropy or gel strength. Based on the proposed predictions of the above-mentioned parameters that are significant to avoid formation damage while drilling a vertical hole. The present article analysis the data related to efficient drilling operations, hole cleaning for a vertical well and the results revealed that mud rheology, density, transport velocity, pipe rotation and the depth of the well are the controlling factors that influence hole cleaning.

Large quantity of heavy oil resources are present in variety of complex thin reservoirs in Lloydminster area which are situated in east-central Alberta and west-central Saskatchewan. Primary depletion and waterflooding are the principal recovery techniques. Although these techniques work, the recovery factors remain low and large volumes of oil are left unrecovered when these methods have been exhausted. Because of the large quantities of sand production, many of these reservoirs end up with a network of wormholes that makes most of the displacement type enhanced oil recovery techniques inapplicable. Because of these high conductivity channels, only gravity drainage based techniques have a good chance of success. Among the applicable methods in Lloydminster area, SAGD has not received adequate attention, mostly due to the notion that heat loss in thin reservoirs would make the process uneconomical. While this may be true, the limiting reservoir thickness for SAGD under varying conditions has not been established. These reservoirs contain light oil with sufficient mobility. Therefore the communication between the SAGD well pairs is no longer a hurdle. This opens up the possibility of increasing the distance between the two wells and introducing elements of steamflooding into the process in order to compensate for the small thickness of the reservoir. The main objective of this study was to evaluate the effect of well configuration on SAGD performance and develop a methodology for enhancement of the SAGD performance through optimizing the well configurations for Lloydminster type of reservoir. A new well configuration was able to significantly improve the application of SAGD in thin reservoirs of Lloydminster. It provided high RF at reasonable cSOR. The effects of some common Lloydminster reservoir characteristics, which are problematic for the SAGD process (such as initial gas saturation, bottom water, and gas-cap) were investigated for the most promising well configuration.

For the most part, Surface tension is relying upon the force adjusted on a drop that is pending or hanging and inevitably is disengaged. Surfaces of fluids normally covered with what goes about as a tiny film. In spite of the fact that this evident film has little quality, it nevertheless acts like a thin membrane and resists being broken. This accepted to be the reason for the attractive forces between the atoms inside a given framework. All atoms are pulled in one to the next in extent to the result of their masses and conversely as the squares of the separation between them. Surface tension for both mineral and oil crude systems is investigated and the value was recorded. In addition, this value for mineral oil system showed higher value than foamy crude oil system, whereas foamy oil saturated methane crude oil system showed lower value than foamy oil saturated methane mineral oil. Surface tension in its general form is believed to have a significant feature in reservoir engineering calculations as well as in further studies related to improved oil production and in designing enhanced oil recovery plans. Moreover, CH4, C2H6 and CO2 oil systems investigated for the initial production, drawdown experiments. After the investigation, the behaviour is identical for almost one-day and two-days.

Numerous scientists did their studies and conducted various laboratory experiments related to a non-Darcy behavior of a two-phase flow for the past thirty years, and made an effort to clarify the behavior. Non-Darcy flow behavior, phenomena occurred in primary recovery method of reservoirs that have an API degree gravity of less than 20. It was confirmed that it results in greater production. The compressibility of foam fits to be the one of the general fundamental factor that directs the lifetime of a non-Darcy form of two phase flow behavior or also is known as the foamy oil.  In the process of usual drive depletion, foamy oil featured of low production GOR and high daily production rate. Foamy oil is more compressible than conventional solution gas due to the oil that gas dispersed in it; as a result, oil formation volume factor is much higher than that in conventional oil. This paper represents a laboratory data followed by some of the analysis related to the properties of non-Darcy form of two phase flow and that is the compressibility parameter. The experimental results showed that at different saturation pressures and at a room temperature, the trends fit the expected behavior above the saturation pressures. Moreover, the measurements of live oil compressibility were also attempted below the saturation pressures. It was concluded that other properties such as the viscosity is added a significant effect rather than compressibility in the behavior of what so called  foamy oil compared to the presence or absence of asphaltenes and other polar oil components.

-Based on American petroleum institute heavy oil iscategorized to have 10 and 20-degreegravity and a viscosity of thousands of centi-poises that flow under solution gas driveas the mean driving mechanism. thatensues in pressure decline experiments by way of investigationin many laboratory tests worldwide. It is alsobelieved to be avital recovery mechanism in some heavy oil reservoirs in the world, which have revealed more performance in recovery factors when it was compared to Darcy flow behaviour, however Darcy deals with single flow behaviour. Many scholars had investigated heavy oil properties for the past decades, and attempted to explain them. This article shows one of the most significant properties for heavy oil flow which is the compressibility. foamy oil or heavy oil has different properties, such as low production gas oil ratio, high oil viscosity, high daily production rate and high primary recovery factor. The compressibility of the foam turns out to be one of the predominant factor that directs the foamy oil phenomenon. To enumerate the focalaspects affecting the compressibility of the heavy oil, dead oil compressibility for both refined mineral oil and crude oil were measured using the densitometer Paar DMA 45, and then the compressibility of the live oil was measured using the same set-up with the same technique as for the dead oil. Foamy oil is more compressible than conventional solution gas because of the tiny gas bubbles that are diffused in the oil; thus, the oil formation volume factor is much higher than the conventional oil. The experimental results show that at different saturation pressures and room temperature, the trends fit the expected behaviour above the saturation pressures. In addition, the measurements of the live oil compressibility were also attempted below the saturation pressures. It was concluded that the oil viscosity is more dominant factor than compressibility compared to the presence or absence of asphaltenes and other highly polar oil components.