No abstract

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.

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.

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.

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.