Summary The unusually high primary recovery factors (RFs) observed in numerous heavy-oil reservoirs are often attributed to foamy oil flow (i.e., the non-Darcy flow involving formation and flow of gas-in-oil dispersion). It occurs when the wells are produced aggressively at high drawdown pressures that led to conditions in which the viscous forces become sufficiently strong to overcome the capillary forces in pushing dispersed bubbles through pore throats. The role of gravitational forces in generating such dispersed flow has not been studied adequately. This work was intended to evaluate the contribution of gravitational forces in primary depletion of heavy-oil formations under foamy flow conditions. Primary-depletion tests were conducted in a 200-cm-long sandpack that was held in either horizontal or vertical orientation. The results of horizontal depletion tests were compared with the depletion tests conducted with the sandpack in the vertical direction. Vertical depletions showed better recoveries at slower depletion rates compared with horizontal depletions. The RFs of both horizontal and vertical depletions were correlated against the average drawdown pressure available to move the oil. It was found that the RF shows a strong dependence on the average drawdown pressure. It was also found that the curve of RF vs. average drawdown pressure moves slightly toward higher recoveries in the presence of an added foaming agent (i.e., with increased oil foaminess).
Foamy-oil viscosity is a controversial topic among researchers regarding what happens to the oil viscosity when the solution gas starts coming out of solution because of decreasing pressure and the released gas starts migrating with the oil in the form of dispersed gas bubbles. For conventional oils, below the true bubblepoint pressure, the oil viscosity increases as the gas freely evolves from the oil. For foamy oils, it has been suggested that the apparent oil viscosity remains relatively constant or perhaps declines slightly between the true bubblepoint and a characteristic lower pressure, called pseudobubblepoint, which is the pressure at which the gas starts separating from the oil. Below this pressure, the viscosity increases, reaching the dead-oil value at atmospheric pressure. However, it is a well-known fact in dispersion rheology that the viscosity of dispersion is higher than the viscosity of the continuous phase. Therefore, the concept of foamy-oil viscosity being lower than the oil viscosity is counterintuitive. It is likely that the apparent viscosity for flow of foamy oil in porous media is not the true dispersion viscosity because of the size of dispersed bubbles being comparable to the pore sizes.This study investigates this issue by measuring the foamy-oil viscosity under varied conditions. The effect of several parameters, such as flow rate, gas volume fraction, and type of viscometer employed, on foamy-oil viscosity was evaluated experimentally. Three different viscosity-measurement techniques, including Cambridge falling-needle viscometer, capillary tube, and a slimtube packed with sand, were used to measure the apparent viscosity of gas-in-oil dispersions. The results show that the type of measuring device used has a significant effect. The results obtained with Cambridge falling-needle viscometer correlate better with the observed behaviour in the sand-packed slimtube than the capillary viscometer results. Overall, the apparent viscosity of foamy oil was found to be similar to live-oil viscosity for a range of gas volume fractions.
The paper discusses conceptualization, design and implementation of the first ever inflow tracer technology application in UAE carried out in an Abu Dhabi offshore field. Working in offshore environment has challenges related to operations, cost, resource requirements and HSE that requires innovative and cost-effective solutions to improve efficiency. In recent years, controlled release smart tracers have carved out a niche as a proven solution for extended life fluid flow monitoring, thus allowing the engineers and geoscientists to better understand fluid inflow patterns in a well leading to informed decisions on reservoir management and production optimization. Smart tracers have the capability to detect, quantify and monitor phase breakthroughs and understand subsequent influx behavior in the well. Being a pioneer project, critical focus was placed on design, execution, and cost optimization. Smart tracer technology was chosen over conventional production logging as it provided production profile monitoring over time compared to single time measurement when using production logging, substantially lower operating cost as well as no production intervention. A flowback calculation was used inputting static and dynamic reservoir data to understand the flow dynamics that the tracers would encounter. Reservoir permeability profiles, image logs and hole rugosity were utilized to identify potential areas of influx along the wellbore and strategically place specially designed smart oil and water tracers along the ~3300 feet long lateral. Strictly adhering to local environmental regulations, a thorough offshore job hazard analysis was carried out and a risk matrix was framed. A specialized first of a kind closed loop customized sampling procedure was invented to de-risk a hydrogen sulfide (H2S) hazard present during sampling operations. The paper describes the initial results for the first well in the campaign. Sampling strategy consisted of two phases: high-frequency immediately after well commissioning followed by steady state sampling. Samples were collected at the wellhead and analyzed for tracer breakthroughs. Results showed a good calibration with conventional production logging, confirmed well clean-up and yielded crucial information on zonal flow contribution. Utilizing a local cost model, smart tracer technology was found to offer typical cost savings in the order of US$10 million for a ten well program over five years as compared to conventional production logging. The paper offers insights into the first application of controlled release tracers in offshore Abu Dhabi highlighting the best practices in project design, techno-economics, hazard analysis and operational excellence. The success of the project is the first major step towards embracing this advanced technology for reservoir monitoring and surveillance. This opens opportunities for similar applications elsewhere with significant potential to incentivize life-cycle cost of reservoir management and improve hydrocarbon recovery.
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 sandpack. 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. Introduction With high oil prices and the continuous decline of conventional resources, attention is shifting towards heavy oil in many parts of the world. Six to nine trillion barrels, or more than two-thirds of the world's oil resources, are heavy viscous crudes that remain difficult to produce(1). Heavy oil promises to play a major role in the future of the oil industry. Therefore, understanding heavy oil behaviour and improving the recoveries in heavy oil reservoirs is crucial to meeting future energy demand. The high viscosity of heavy oils, typically in the range of 500 to 50,000 cP, results in low recovery factors in primary production. However, some Canadian heavy oil reservoirs produce more than what is expected by the conventional analogs. Primary recovery from these reservoirs could be as high as 15%(2). In conventional solution gas drive, the gas evolves in the pore space and connects with the gas in the other pores forming a free continuous gas resulting in higher gas rates. In heavy oil reservoirs, the gas bubbles tend to remain dispersed within the viscous oil because of the high viscosity, low diffusion rates and higher pressure gradients. This behaviour results in higher oil rates, lower gas-oil ratios and slower pressure decline within the reservoir. The production from this type of reservoir is usually accompanied by sand. The two-phase flow of oil and dispersed gas bubbles is usually referred to as foamy oil flow. Smith(3) appears to be the first researcher who provided an analysis to the anomalous behaviour of the heavy oil reservoirs under solution gas drive using field data. The most common techniques used to produce heavy oil from underground formations involve thermal recovery processes. However, extensive developments in Canada in the period from 1985 to 2005 have resulted in several new heavy oil exploitation technologies. One of the major new technologies in the last two decades is cold heavy oil production with sand (CHOPS)(4).
Cold heavy oil production with sand (CHOPS) is widely used as primary recovery method for heavy oil in western Canada. This process involves sand production in massive amounts. Sand production creates high permeability zones (wormholes) which extend the drainage radius. Typically 5-10% of the OOIP is recovered by this process. Therefore, the need to find a follow-up process is paramount.The objective of this work was to experimentally evaluate the potential of using cyclic CO 2 injection for recovering additional oil from depleted foamy oil reservoirs. A total of five depletion tests were conducted in a two meters long sandpack kept in a vertical orientation. The primary depletions at different depletion rates were followed by one or two huff-npuff cycles of CO 2 injection.The total recovery factor after cyclic CO 2 injection reached 30% indicating the potential of solvent injection as a secondary oil recovery method. Interestingly, the recovery after the cyclic CO 2 injection was more or less independent of depletion rate used in the primary production. It was found that the cyclic CO 2 injection was more efficient when the primary depletion was at slow rate and resulted in lower primary depletion recovery.The results of this study show that it may be possible to re-energize the depleted heavy oil reservoirs by injecting CO 2 , especially those that did not give high recovery factors during the primary depletion.
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