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Brij B. Maini - One of the best experts on this subject based on the ideXlab platform.

  • influence of fluid and operating parameters on the recovery factors and Gas oil ratio in high viscous reservoirs under foamy Solution Gas Drive
    Fuel, 2017
    Co-Authors: Bashir Suleman Abusahmin, Rama Rao Karri, Brij B. Maini
    Abstract:

    Abstract Foamy oil flow behavior is reported in several high viscous reservoirs in the world, wherein reduction of pressure was noticed to be the main factor of such characteristics. It is also believed to be a significant recovery mechanism in numerous high viscous heavy oil reservoirs that have revealed higher recovery factors when compared with the fluid flow using ordinary Darcy equation. This research investigates the effects of number of factors that influence the oil recovery trends, as well as the production rates in high viscous reservoirs under foamy Solution Gas Drive behavior. The factors investigated comprised of refined mineral oil versus crude oil, saturation pressure, oil viscosity, drawdown pressure, flow direction, Solution Gas, pressure depletion rate and Gas oil ratio (GOR). Live oil-Gas system is prepared by blending a mixture of dead oil with Gases such as CO 2 , ethane and methane. Each high viscous live oil system was completely characterized by evaluating fluid parameters and operating parameters. The significant outcome of the depletion tests confirms that the decreasing pressure depletion rate result in lower performance. At the similar rate of pressure depletion, higher oil recovery was obtained with methane saturated oil compared to either ethane/CO 2 systems, even though it had the lowest Solution GOR. At saturation pressure of 500 psi, the Solution GOR was 9.1 m 3 /m 3 , 28 m 3 /m 3 and 33 m 3 /m 3 with methane, CO 2 and ethane Gas respectively, whereas Solution GOR of methane saturated with crude oil were found to be 11 m 3 /m 3 . Both mineral and crude oil systems displayed similar decline in the oil recovery performance with decreasing pressure depletion rate. In high depletion rate tests, the recovery factor was 26.1%, 23.7% and 19.6% with respect to methane, ethane and CO 2 respectively, whereas in slow depletion runs, the recovery factor declined from 13.1% with methane to 5.5% with CO 2 .

  • Application of Foamy Mineral Oil Flow under Solution Gas Drive to a Field Crude Oil
    2016
    Co-Authors: Bashir Busahmin, Brij B. Maini, Hossein Hejazi, Amin Sharifi, Mohammad Tavallali
    Abstract:

    Heavy oil flow in the form of foamy oil under Solution Gas Drive is widely observed in many Canadian reservoirs. Despite the importance of such phenomenon, complexity involved in foamy oil flow in porous media is not well understood. Series of numerical simulations were performed to model experiments that were carried out in a two meter long Sand pack to investigate the conditions required to increase oil production under Solution Gas Drive mechanism. Through these experiments the Solution Gas Drive performance at different depletion rates were analyzed. Creation of foamy heavy oil is thought to be responsible for higher recovery factors compared to what is expected from the conventional Solution Gas Drive theory. However, the complex nature of foamy oil and different transport parameters are yet to be understood.The results of this study can be used to numerically model foamy-oil mechanism in heavy oil reservoirs. Furthermore, the results can be applied for reservoir production optimization as well as management. A new model has been developed using commercial numerical simulator, computer modeling group, (CMG-STARS TM ). By using the experimental data, different experimental production histories have been matched. Effect of different parameters such as fluid and reservoir properties and depletion rate on foamy oil recovery have been evaluated. The results reveal that despite many difficulties, foamy oil flow through porous media can be numerically modeled. However these models will strongly depend on a good understanding of many different parameters including rock-fluid interaction, as well as the depletion rates.

  • Foamy Oil Flow and its Role in Heavy Oil Production
    2010
    Co-Authors: Brij B. Maini, Bashir Busahmin
    Abstract:

    Two‐phase oil‐Gas flow in porous media is often encountered during oil production from oil bearing sedimentary rocks. Traditionally such flow is modeled by extending the Darcy’s law to two‐phase flow by employing the concept of saturation dependent relative permeability. This model is remarkably successful as long as the fluid distribution within the porous medium is controlled by capillary forces. Under this condition, the two fluids appear to flow in their own continuous flow channels. This flow description is applicable to most reservoir flow scenarios encountered in light oil production. However, in primary production of heavy oil under Solution‐Gas Drive, this flow model often fails to provide a satisfactory match of the observed behaviour.Many heavy oil reservoirs under Solution Gas Drive show much higher rate of oil production and final recovery factor than what would be predicted by the theory based on the conventional two‐phase flow model. Different mechanisms have been postulated to explain the ...

  • Role of Asphaltenes in Foamy Oil Flow
    Journal of Canadian Petroleum Technology, 2007
    Co-Authors: I. Adil, Brij B. Maini
    Abstract:

    It has been suggested in several studies that there may be a link between the presence of high asphaltenes content and the foamability of oil. However, a systematic examination of the impact of asphaltenes on the performance of Solution Gas Drive, in connection with foamy oil flow, has not been reported. This paper presents an experimental study that addresses this issue. The objective of this work was to examine whether or not the presence of asphaltenes has a strong influence on the performance of foamy Solution Gas Drive. To this end, parallel Solution Gas Drive experiments were conducted using a heavy crude oil from the Lloydminster area and a deasphalted version of the same oil. To eliminate the influence of oil viscosity, the viscosity of the crude oil was reduced to the same level as that of the deasphalted oil by diluting it with a 50-50 mixture of heptane and toluene. The experiments were carried out in a visual sandpack that permits observation of bubble formation in the sand. The results show that the presence of asphaltenes significantly promotes foamy oil flow.

  • Effect of Foaminess on the Performance of Solution Gas Drive in Heavy Oil Reservoirs
    Journal of Canadian Petroleum Technology, 2007
    Co-Authors: Ahmed Alshmakhy, Brij B. Maini
    Abstract:

    Some heavy oil reservoirs under Solution Gas Drive show abnormally high final recoveries. One of the mechanisms to explain these phenomena is the foamy oil flow effect which occurs under certain operating conditions. It has been studied extensively, yet remains poorly understood and difficult to model. The objective of this work was to investigate the effect of oil foaminess on the performance of Solution Gas Drive in heavy oil reservoirs. In this research, the first step was to find a foaming agent that will have a measurable effect on foam stability of a viscous mineral oil. A simple experimental procedure was developed to quantify the oil foaminess in the presence of an added foaming agent. Several depletion tests were conducted with the added foaming agent at different depletion rates using a two metre long sand-pack. The experimental results showed that the increased foaminess of oil did not have a significant effect on the Solution Gas Drive performance when the depletion rate was high. However, in a slow depletion test, the effect of oil foaminess was significant.

Changfa Wang - One of the best experts on this subject based on the ideXlab platform.

  • Experimental study and new three-dimensional kinetic modeling of foamy Solution-Gas Drive processes
    Scientific Reports, 2018
    Co-Authors: Xiaofei Sun, Zhaoyao Song, Yanyu Zhang, Peng Li, Shilin Wang, Changfa Wang
    Abstract:

    Foamy Solution-Gas Drive processes in heavy oil reservoirs are very complex. The influence of some microscopic factors on this process is not fully understood due to limitations of traditional depletion tests. This study aims to investigate foamy Solution-Gas Drive by experiments and simulations. First, the effects of the pressure depletion rate on critical Gas saturation and foamy Solution-Gas Drive processes were investigated by laboratory experiments. Second, a new three-dimensional foamy oil model that captures many important characteristics of foamy Solution-Gas Drive, such as non-equilibrium behavior, Gas evolution kinetics, and the effect of viscous forces on Gas mobility, was developed. Last, the effects of some important parameters on foamy Solution-Gas Drive were systematically investigated,and a model application was conducted in a typical foamy oil reservoir. The results indicate that the new model is capble of simulating many of the unusual behaviors observed in foamy Solution-Gas Drive on a laboratory and field scales. High oil recoveries were obtained with a high oil viscosity, high depletion rate, long sandpack, and low Solution Gas-oil ratio. Foamy Solution-Gas Drive processes are sensitive to the depletion rate, length, and critical Gas saturation. The oil viscosity, Solution GOR and diffusion coefficient are not sensitive factors.

Abbas Firoozabadi - One of the best experts on this subject based on the ideXlab platform.

  • effect of gor temperature and initial water saturation on Solution Gas Drive in heavy oil reservoirs
    Spe Journal, 2005
    Co-Authors: G. Tang, Abbas Firoozabadi
    Abstract:

    We have carried out an extensive set of tests on Solution-Gas Drive for a heavy oil to study the effects of initial water saturation, temperature, and Gas-oil ratio (GOR). The viscosity and the API gravity of the stock-tank oil from Hamaca field (in Venezuela) used in our tests are 560,000 cp (at 24°C) and 8.7, respectively. The Solution-Gas Drive tests were conducted using live oils with Solution GOR of 6.5, 9.0, and 12.2 (vol/vol at standard conditions). In two tests, initial water saturations of 4.0 and 5.2% were established. Five tests were conducted at a temperature of 35°C; one test was conducted at 46°C. The duration for each test was approximately 3 months. The following conclusions are drawn based on the results from all the tests. Initial water saturation decreases Gas-bubble density. The recovery efficiency decreases because of an increase in Gas mobility with increase in initial water saturation. As the temperature increases from 35 to 46°C, the Gas relative permeability increases one order of magnitude, which in turn results in a reduction of recovery efficiency. The temperature effect on recovery is in agreement with our previous work with temperature increase from 24 to 35°C. Increase in Solution GOR has a significant effect on the Gas-bubble nucleation process, mainly because of change in interfacial tension. For all the tests conducted, the oil recovery by Solution-Gas Drive at test termination was approximately 16% and higher.

  • Gas oil ratio temperature and initial water saturation effects on Solution Gas Drive
    2001 SPE Annual Technical Conference and Exhibition, 2002
    Co-Authors: Ghanshyabhai Tank, Abbas Firoozabadi
    Abstract:

    The effects of initial water saturation, S wi , temperature, and Gas/oil ratio (GOR) on Solution-Gas Drive in heavy oils were studied. The viscosity and gravity of the stock-tank oil used in the tests were 560,000 cp and 8.7°API. In two tests, 4.0 and 5.2% S wi were used. Five tests were conducted at 35°C, and one test was conducted at 46°C.

  • Gas/oil ratio, temperature, and initial water-saturation effects on Solution-Gas Drive
    Journal of Petroleum Technology, 2002
    Co-Authors: Ghanshyabhai Tank, Abbas Firoozabadi
    Abstract:

    The effects of initial water saturation, S wi , temperature, and Gas/oil ratio (GOR) on Solution-Gas Drive in heavy oils were studied. The viscosity and gravity of the stock-tank oil used in the tests were 560,000 cp and 8.7°API. In two tests, 4.0 and 5.2% S wi were used. Five tests were conducted at 35°C, and one test was conducted at 46°C.

Anthony R Kovscek - One of the best experts on this subject based on the ideXlab platform.

  • oil chemistry and its impact on heavy oil Solution Gas Drive
    Journal of Petroleum Science and Engineering, 2009
    Co-Authors: J Peng, G. Tang, Anthony R Kovscek
    Abstract:

    Abstract A series of laboratory depletion experiments are conducted at reservoir temperatures with three different live crude oils, as well as mineral oils. These tests examine the role of oil composition on the heavy-oil Solution Gas Drive process. The morphology of Gas bubbles, pore pressure, critical Gas saturation and oil recovery is compared. Core-level depletion indicates that oil composition plays a role in determining metastability of dispersed Gas bubbles in foamy oil. Generally, systems that exhibit effluent Gas bubbles on the order of the size of pores tend to recover more oil, all other factors being equal. The concentration of organic acid and base groups as well as asphaltene content of crude oil is measured to characterize each crude-oil sample and develop an understanding of the influence of oil chemistry. Results suggest that significant asphaltene content as well as substantial acid number (the amount of potassium hydroxide in milligrams that is needed to neutralize the acid groups in one gram of crude oil) and base number (the amount of potassium hydroxide in milligrams needed to neutralize the acid titrant for one gram of crude oil) are indicators of whether oil is foamy. The partitioning of acid and base groups between the asphaltene fraction and deasphalted oil is also studied. Organic acid and base groups are clearly present in the asphaltene fraction. The role of such functional groups on oil foam stability is investigated by measuring the lifetime of single foam films formed from crude oil and asphaltene Solutions. Transparent micromodels etched with a sandstone pore network and containing Gas dispersed within the oil are also used to investigate the correlation of acid number, base number, and asphaltene content on Gas-bubble coalescence. The results show that a high concentration of asphaltene that exhibits acid and base functional groups tends to increase foamability and film lifetime of Gas/crude-oil dispersions. The deasphalted fraction is not foamy despite possessing significant acid and base number. We conclude that acid and base groups within asphaltene, and their interaction at the Gas–oil interface, are a source of interfacial stability.

  • A microvisual study of Solution-Gas-Drive mechanisms in viscous oils
    Journal of Petroleum Science and Engineering, 2004
    Co-Authors: D.s. George, O. Hayat, Anthony R Kovscek
    Abstract:

    Abstract The literature suggests that oil-phase viscosity has a profound effect on oil production during Solution Gas Drive. Some heavy-oil reservoirs show higher than expected production rates, produced Gas–oil ratio (GOR) close to Solution GOR, and relatively high recovery. The reasons for this behavior are not clear, but it has been suggested that Gas-phase nucleation, growth of Gas bubbles, and eventual coalescence into a continuous Gas phase must be examined in detail to interpret better recovery. To this end, Solution-Gas-Drive (depletion) experiments were conducted in micromodels, oil-lens drainage was observed and modeled in cornered capillary tubes, and bubble growth modeled. Experiments and calculations were conducted with viscous and low-viscosity liquids to probe explicitly the effect of Solution viscosity. A micromodel is a two-dimensional representation of pore space. The micromodels employed are etched from silicon and exhibit pore body and throat sizes equivalent to a representative sandstone. Likewise, they capture many aspects of pore-wall roughness. Micromodels are housed in a pressure vessel to allow experimentation at elevated pressure. Pore-level events are viewed through an optical microscope. Spatial reSolution of events within the micromodel is on the order of 1 μm. Nucleation occurs repeatedly and regularly at surface roughness. Nucleated bubbles grow to fill pores before they are mobilized. Interestingly, Solution viscosity appears to slow considerably the coalescence of Gas. For coalescence of two Gas bubbles into a single bubble, the liquid lens separating the bubbles must drain. Experimental results in micromodels and triangular capillary tubes indicate that when oil-phase viscosity is high, the rate of coalescence of Gas bubbles is slow. Capillary tube experiments are modeled exactly with no adjustable parameters. It is shown that the period of time for drainage is at least linearly proportional to the liquid viscosity. The implication for recovery of viscous oil is that the produced Gas–oil ratio and Gas-phase relative permeability remain relatively low because Gas bubbles remain dispersed. Correspondingly, oil-phase relative permeability remains high contributing to relatively efficient oil recovery despite high oil-phase viscosity.

  • heavy oil Solution Gas Drive a laboratory study
    Journal of Petroleum Science and Engineering, 2002
    Co-Authors: Serhat Akin, Anthony R Kovscek
    Abstract:

    Abstract When some heavy-oil reservoirs are produced using Solution Gas Drive, they show: (1) higher than expected production rates, (2) low produced Gas–oil ratio, and (3) relatively high recovery. The reasons for this behavior are not clear. A series of X-ray computerized-tomography (CT)-monitored, heavy-oil pressure depletion experiments were carried out to examine the core-scale phenomena using high pressure/high temperature equipment. Viscous white mineral oil ( μ =220 cp at 20 °C) and 9° API heavy crude oil from the Hamaca region of the Orinoco Belt, Venezuela, were used. A transparent cell attached to the outlet of the sand pack allowed monitoring of bubble size and shape as bubbles exited the sand pack. Conventional Solution-Gas-Drive behavior was observed in the experiments conducted with the mineral oil: large regions of pore space within the core became saturated with a continuous Gas phase and ample Gas mobilization was witnessed. In the heavy-crude-oil experiment, however, it was inferred that Gas bubbles were of slightly greater size than pore dimensions. The fraction of Gas mobilized was not large. The difference in behavior between mineral oil and crude oil results suggests an effect due to large oil-phase viscosity, relatively rapid depletion rate, and possibly the high asphaltene content of Hamaca crude oil. Critical Gas saturation was gauged as the saturation at which mobile Gas was first observed regardless of whether the Gas was continuous. For both experiments, the critical Gas saturation was observed to be around 3% to 4%.

  • Mechanistic modeling of Solution-Gas Drive in viscous oils
    Journal of Petroleum Technology, 2001
    Co-Authors: P. Arora, Anthony R Kovscek
    Abstract:

    Solution-Gas Drive in reservoirs con taining heavy and viscous oil is not well understood. The full-length paper develops a mechanistic population-balance model for describing the bubble-nucleation and -growth process. Appropriate rate equations are derived for instantancous-nucleation (IN) and progressive-nucleation (PN) theories. The PN model matches the experiments somewhat better but is more computationally demanding. The population-balance description of both models does not require a critical supersaturation to be exceeded before bubble-nucle ation and -growth onset. Liberation of Gas from Solution at the thermo dynamic bubblepoint, and bubble-growth equations presented describe Gas-phase kinetics and pressure response of the systems examined.

  • Mechanistic Modeling of Solution Gas Drive in Viscous Oils
    SPE International Thermal Operations and Heavy Oil Symposium, 2001
    Co-Authors: P. Arora, Anthony R Kovscek
    Abstract:

    Solution Gas Drive in reservoirs containing heavy and viscous oil is not well understood. This paper develops a mechanistic population balance model for describing the process of bubble nucleation and growth. The model is applied to both light and viscous oils. The primary modeling concept is a continuum bubble population balance. Appropriate rate equations are derived for two theories of bubble nucleation described in the literature—instantaneous nucleation (IN) and progressive nucleation (PN). The results of simulations for the IN and PN models are compared to experimental data reported elsewhere for light oil and to new data for viscous oils. Model parameters are all physically based. Within the IN model, the number density of bubbles must be specified while the PN model requires the cavity size distribution of the porous medium as input. The PN model matches the experiments somewhat better, but is more demanding computationally. Interestingly, the population balance description of either model does not require a critical supersaturation to be exceeded before the onset of bubble nucleation and growth. Supersaturation is the difference between the equilibrium and dynamic liquid pressure of a system. Liberation of Gas from Solution at the thermodynamic bubble point and the bubble growth equations presented here well describe the kinetics of the Gas phase and pressure response of the systems examined.

Albert C. Reynolds - One of the best experts on this subject based on the ideXlab platform.