Many heavy oil reservoirs contain oil that has some limited mobility under reservoir conditions. In these reservoirs, a small fraction of the oil-in-place can be recovered using the internal reservoir energy through heavy oil solution gas drive (primary production). An integral part of this process is the so-called 'foamy oil mechanism', whereby oil is produced as a gas-in-oil dispersion. At the end of primary production, the bulk of the oil is still in place, while the natural energy of the reservoir has been depleted. This remaining oil is still mostly continuous and presents a valuable target for further recovery. Many of these reservoirs are relatively small or thin, or may be contacted by overlying gas or underlying water. As such, they are poor candidates for thermal oil recovery methods, so any additional oil recovery after primary production must be non-thermal. In this work, we present experimental results of foamy oil depletion at two different length scales and varying depletion rates. Tests were conducted in the absence of sand production, and the results from the depletion experiments are interpreted in terms of viscous forces. At the conclusion of primary recovery, the potential for further non-thermal exploitation of these reservoirs is explored. Results for waterflooding and chemical flooding are presented, demonstrating the viability of these techniques for heavy oil EOR. Several displacement mechanisms are identified through the secondary and tertiary processes that contribute to significant (although potentially slow) incremental recovery of heavy oil. Introduction Many countries have heavy oil reservoirs. Canada and Venezuela in particular contain some of the largest heavy oil and bitumen resources in the world. Rising energy demands, coupled with a decline in conventional oil reserves, has led to increased interest in heavy oil recovery in recent years. The size of these heavy oil deposits is considerable, and with volatile crude oil prices making it difficult to produce from some higher viscosity bitumen reservoirs, production of heavy oil could potentially be very important in years to come. Understanding the mechanisms by which heavy oil can be displaced in reservoirs is crucial to the successful recovery of this resource base. Heavy oil can be defined as a class of oils with viscosity ranging from 50 mPa.s up to around 50,000 mPa.s. This oil has limited mobility under reservoir temperature and pressure, and Darcy's Law predicts that the oil can flow slowly under high applied pressure gradients. However, it has been observed that in these reservoirs, solution gas drive leads to significantly higher rates and recoveries than what was expected by conventional understanding of gas-oil relative permeability behaviour(1). This behaviour, first reported in Canadian heavy oil, has since been observed in many other reservoirs around the world including South America, China and Albania. Investigations into the causes of this abnormal, but fortuitous, primary production response have been the focus of many publications in the past 25 years. The recovery from primary production in heavy oil reservoirs may be as high as 20%(2), but is usually lower.

Foamy oil solution gas drive mechanisms are complex and our knowledge and understanding is limited despite extensive studies in the literature. In order to advance our understanding of heavy oil solution gas drive mechanisms, long core depletion experiments were designed. These experiments were performed on sand-filled or glass bead-filled tubes that are x-ray transparent and have pressure transducers along their length. The novelty of the experiments is the length that they extend (over 18 m) and the duration of the experimental runs. The results of the longer experiments should be able to provide data that bridge the gap between the field scale and the shorter laboratory experiments that have been performed in the past. Thus, production, pressure transient and saturation data are presented in this 'extended' scale. In addition, CT scanner images are expected to provide information about the evolution of gas. Introduction Sand production increases the permeability of unconsolidated sand reservoirs through the establishment of wormholes. These higher permeability regions, in combination with heavy oil solution gas drive, recover heavy oil through primary production (Cold Heavy Oil Production with Sand or CHOPS). A better understanding of the fluid-rock interaction can be established by studying the effect of permeability and geometry of the experiments. Bubble growth in a porous medium is initially controlled by the geometry of the pores, the pore walls and capillary forces(1). Dumore(2) compared two different permeability sandpacks and saw that the gas remaining dispersed for longer in the high-permeability sandpack. Wall and Khurana(3) observed that lower permeability cores resulted in higher gas saturation within the core. Therefore, they suggested that the free gas saturation depends on capillarity. Sarma and Maini(4) found that, although higher production was obtained with a higher permeability core, the general trend for pressure and production as a function of time were the same as the lower permeability core. Firoozabadi et al.(5) observed lower supersaturations and lower critical gas saturation were obtained from lower permeability depletion experiments. Tang et al.(6) saw that poorly packed areas had higher gas saturation as a result of lower capillary forces in higher porosity areas. In higher permeability porous media, trapping due to capillary forces is lower as a result of larger pore sizes. Therefore, the flow of the fluid is less hindered, giving the newly nucleated gas less time to grow within the pores before it begins to move with the oil. This causes the gas to remain dispersed within the oil for a longer time before the gas coalesces, compared to lower permeability sandpacks. High depletion rates are necessary when field observations of heavy oil solution gas drive are reproduced in the laboratory. As a result, there have been numerous investigations in the literature that study the effect of the depletion rate(7–10). High depletion rates are considered representative of near wellbore behaviour while low depletion rates represent field conditions. By increasing the length of the sandpack to a much larger scale, it should be possible to capture the pressure, saturation and production behaviour both near and further from the wellbore in a single experiment.

fax 01-972-952-9435. AbstractIn this paper, we propose the combined utilization of x-ray tomography and magnetic resonance techniques for quantification of heavy oil fluid properties. The design of these systems is presented along with preliminary results combined with conventional measurements. The objective is to understand the PVT behavior of a viscous heavy oil from a reservoir that has undergone primary production. Methane is dissolved into the oil at ambient temperature and elevated pressure. The pressure is later slowly depleted and the oil PVT properties are recorded. Specifically, this paper details measurements of oil density, formation value factor, and solution gas-oil-ratio as a function of pressure.The incremental benefit of the proposed nucleonic techniques is that they provide more detailed information about that oil, compared to conventional PVT measurements. This improves our understanding of the foamy oil response.

Summary Investigating the properties of live heavy oil, as pressure declines from the original reservoir pressure to ambient pressure, can aid in interpreting and simulating the response of heavy-oil reservoirs undergoing primary production. Foamy oil has a distinctly different and more complex behavior compared to conventional oil as the reservoir pressure depletes and the gas leaves solution from the oil. Solution gas separates very slowly from the oil; thus, conventional pressure/volume/temperature (PVT) measurements are not trivial to perform. In this paper, we present novel experiments that utilize X-ray computerized assisted technology (CT) scanning and low field nuclear magnetic resonance (NMR) techniques. These nondestructive tomographic methods are capable of providing unique in-situ measurements of how oil properties change as pressure depletes in a PVT cell. Specifically, this paper details measurements of oil density, oil and gas formation volume factor, solution gas/oil ratio, (GOR), and oil viscosity as a function of pressure. Experiments were initially performed at a slow rate, as in conventional PVT tests, allowing equilibrium to be reached at each pressure step. These results are compared to non-equilibrium tests, whereby pressure declines linearly with time, as in coreflood experiments. The incremental benefit of the proposed techniques is that they provide more detailed information about the oil, which improves our understanding of foamy-oil properties. Introduction Understanding fluid behavior of heavy oils is important for reservoir simulation and production response predictions. In heavy-oil reservoirs, the oil viscosity and density are commonly reported, but there is little experimental data in the literature reporting how oil properties change with pressure. This information would be especially useful for production companies seeking to understand and improve their primary (cold production) response. It is already widely known that foamy-oil behavior is a major cause for increased production in cold heavy-oil reservoirs along with sand production. Therefore, it would be valuable to first study the bulk fluid properties of live heavy oil prior to sandpack-depletion experiments. If the response of these properties to incremental pressure reduction can be established, this can be compared with fluid expansion during pressure depletion in a sandpack. CT scanning is useful in studying high-pressure PVT relationships. Images of a pressure vessel filled with live oil can be taken as the volume of the vessel is expanded and used to calculate bulk densities and free gas saturation. Also, CT images allow us to visually see where free gas is formed in the vessel. For example, CT scanning can be used to provide an indication of whether or not small bubbles nucleate within the oil and then slowly coalesce into a gas cap, or if free gas forms straight away. CT scanning provides much more information than conventional PVT cells. Uncertainties about where gas is forming in the oil, its effect on oil properties, and transient behavior cannot be reconciled in conventional PVT cells. Also, from CT images, the formation of microbubbles could be inferred based on the density of the oil with the dissolved gas. If the oil density decreases below the bubblepoint pressure, then it is likely that gas has come out of solution but remains within the oil; therefore, the resulting mixture is less dense than the original live oil. However, if oil density increases as the gas evolves, then the oil does not contain small gas bubbles, and gas has separated from the oil. Also, the free gas saturation growth with time, and comparison of images at equilibrium vs. immediately after the expansion of the vessel, can provide mass transfer information about gas bubble growth, supersaturation, and gravity separation. When characterizing heavy oil and bitumen fluid properties, oil viscosity is one of the most important pieces of information that has to be obtained. The high viscosities of heavy oil and bitumen present a significant obstacle to the technical and economic success of a given enhanced oil recovery option. As a result, in-situ oil viscosity measurement techniques would be of considerable benefit to the industry. In heavy-oil reservoirs that are undergoing primary production, this problem is further complicated by the presence of the gas leaving solution with the oil. Above the bubblepoint, the gas is fully dissolved into the oil; thus, the live oil exists as a single-phase fluid. Once the pressure drops below the bubblepoint and gas begins to leave solution, the oil viscosity behavior is no longer well understood. In addition to our CT analysis, this work also presents the use of low field NMR as a tool for making in-situ viscosity estimates of live and foamy oil. NMR spectra change significantly as pressure drops and gas leaves solution, and these changes can be correlated to physical changes in the oil viscosity.

No abstract

In this paper, we propose the combined utilization of x-ray tomography and magnetic resonance techniques for quantification of heavy oil fluid properties. The design of these systems is presented along with preliminary results combined with conventional measurements. The objective is to understand the PVT behavior of a viscous heavy oil from a reservoir that has undergone primary production. Methane is dissolved into the oil at ambient temperature and elevated pressure. The pressure is later slowly depleted and the oil PVT properties are recorded. Specifically, this paper details measurements of oil density, formation value factor, and solution gas-oil-ratio as a function of pressure. The incremental benefit of the proposed nucleonic techniques is that they provide more detailed information about that oil, compared to conventional PVT measurements. This improves our understanding of the foamy oil response. Introduction Understanding fluid behavior of heavy oils is important for reservoir simulation and production response predictions. In heavy oil reservoirs, the oil viscosity and density are commonly reported, but there is little experimental data in the literature reporting how oil properties change with pressure. This information would be especially useful for production companies seeking to understand and improve their primary (cold production) response. It is already widely known that foamy oil behavior is a major cause for increased production in cold heavy oil reservoirs along with sand production. Therefore it would be valuable to first study the bulk fluid properties of live heavy oil prior to sand pack depletion experiments. If the response of these properties to incremental pressure reduction can be established, this can be compared with fluid expansion during pressure depletion in a sand pack. Computer Assisted Tomography (CT) scanning is useful in studying high-pressure PVT relationships. Images of a pressure vessel filled with live oil can be taken as the volume of the vessel is expanded and used to calculate bulk densities and free gas saturation. Also, CT images allow us to visually see how the gas comes out of solution and where it is located in the vessel. For example, CT scanning can be used to provide an indication of whether or not small bubbles nucleate within the oil and then slowly coalesce into a gas cap, or if free gas forms straight away. CT scanning provides much more information than conventional PVT cells. Uncertainties about where gas is forming in the oil, its effect on oil properties and transient behavior cannot be solved in conventional PVT cells. However, from CT images the formation of micro bubbles could be inferred based on the density of the oil with the dissolved gas. If the oil density decreases as the pressure drops, then it is likely that gas has come out of solution but remains within the oil, hence the resulting mixture is less dense than the original live oil. However, if oil density increases as the gas evolves then the oil does not contain small gas bubbles, and gas has separated from the oil. Also, the free gas saturation growth with time, and comparison of images at equilibrium vs. immediately after the expansion of the vessel, will provide mass transfer information about gas bubble growth, supersaturation and gravity separation. When characterizing heavy oil and bitumen fluid properties, oil viscosity is one of the most important pieces of information that has to be obtained. The high viscosities of heavy oil and bitumen present a significant obstacle to the technical and economic success of a given EOR option. As a result, in-situ oil viscosity measurement techniques would be of considerable benefit to the industry.