Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
Collaborating Authors
Results
Abstract Multiple contact miscible floods involving the injection of relatively inexpensive gases into oil reservoirs represent one of the most cost effective enhanced oil recovery processes currently available. The experimental displacement procedures available for determining the optimal flood pressure, referred to as the minimum miscibility pressure (MMP), are both costly and time consuming. Hence, the use of a correlation proven reliable over a large range of conditions would likely be considered acceptable for the purposes of preliminary screening studies. This paper presents an evaluation of 15 rich gas, lean gas, and nitrogen MMP correlations published in the literature. Each method was developed using experimental data, equation-of-state (EOS) predictions, or a combination of the two. The accuracy of each correlation was evaluated by comparing predicted versus measured MMP's using a data base consisting predominantly of experimental results published in the literature. The most reliable MMP correlations were all found to have a common EOS developmental basis. These results support the applicability of EOS-based methods for accurate MMP predictions. Introduction The injection gases most commonly used for enhanced oil recovery processes are generally not miscible upon first contact with the reservoir fluids that they are displacing. However, under suitable reservoir pressure and temperature conditions, miscibility may gradually be developed between some injection-gas/reservoir-oil combinations by a mass transfer of components between the gaseous and liquid phases. Miscibility generated in such a manner is commonly referred to as multiple contact (dynamic) miscibility, and has been well described in the literature. The vaporizing gas drive (VGD) and the condensing gas drive (CGD) are the mechanisms through which dynamic miscibility is generally explained. Miscibility develops at the flood front during VGD processes, which are commonly referred to as lean gas (LG) drives. Dynamic miscibility in nitrogen (N2) floods similarly occurs through the VGD mechanism. During CGD processes, generally referred to as rich gas (RG) drives, miscibility develops at the injection point. Recent research has indicated, however, that miscibility in some RG drives may actually develop through a liquid extraction drive (LED) process. Similar to VGD's, miscibility develops at the flood front during a LED. An optimum displacement pressure exists for a dynamic miscible flood, commonly referred to as the minimum miscibility pressure (MMP). The object of this study is to evaluate available RG, LG, and N2 MMP correlations using a data base consisting predominantly of experimental MMP results published in the literature. Measurement and Prediction of MMP's The MMP for gas/oil mixtures has traditionally been measured by performing slim tube displacement experiments. These experiments involve constant temperature displacement of a live oil from the slim tube by an injection gas. The MMP has typically been accepted as the pressure at which a practical maximum recovery efficiency is observed following a series of displacements. MMP values have also been measured for many gas/oil pairs using the Rising Bubble Apparatus (RBA), where a small bubble of gas is injected at the base of a column of live oil.
Abstract The investigation into mobility control and blocking agents to improve steamflood conformance has been of ongoing interest. This paper examines the thermal stability and application of oil-in-water macroemulsions to block high permeability channels created by steam injection. The stability of 5% (by volume) Primrose and Lloydminster heavy oil-in-water emulsion was screened using both an anionic (Vista 250) and a nonionic (Triton X-100) surfactant. Surfactants were used in active concentrations of 25 to 5000 ppm to create the emulsions. Visual observations of the droplet character and the emulsion pH behaviour at different surfactant concentrations, over cure temperatures of 25 ยฐC to 225 ยฐC. were the criteria used to determine stability. Results of this work indicate the Vista 250 was superior to the Triton X-100 with respect to maintaining emulsion stability at high temperatures. The optimal surfactant concentration for creating 5% oil-in-water emulsions and maintaining their stability was found to be in the range of 50 to 300 ppm jar the surfactants used here. Recovery and steamflood behaviour were observed in an unscaled linear model containing an oil saturated single size sand. Comparative results using a heterogeneous model containing two parallel oil saturated sand beds of different permeabilities show early breakthrough and reduced recovery due to steam channelling. Externally prepared emulsion (5% oil content. 100 ppm Vista 250) was then injected to block the more permeable channels. Blockage was tested using the emulsion injected as a slug followed by steam and with the emulsion co-injected with steam. During slug injection the emulsion was injected at a constant pressure with a permeability reduction on the order of 90% inferred from a change in flow rate data, Emulsion slug injection was more effective with respect to improved blocking and recovery than was the co-injection of emulsion and steam for both heavy oils. The strategy behind this research was to examine from a mechanistic standpoint if the application of a stable heavy oil emulsion as a high temperature blocking agent would result in improved oil recovery in an unsealed physical model- No attempt was made to assess the economic viability of the process for implementation in the field. Laboratory assessment of the process for field implementation would require a scaled physical model. Currently, the integration of scaled emulsion criteria with scaled reservoir criteria for physical and numerical simulation poses a challenging problem. The authors believe this process would warrant further investigation for potential application to a heavy oil reservoir with a bottom water zone as well as stratified or heterogeneous reservoirs. Introduction In the application of steam injection to heterogeneous reservoir there is a tendency for steam and steam condensate to channel through high-permeability zones, thus leaving a significant amount of oil unrecovered. Many techniques have been proposed from controlled permeability reduction to outright plugging of channel zones through the use of blocking agents. However, to be successful the blocking agent must withstand the harsh environment associated with hightemperature steamflooding. The use of oil-in-water macroemulsions as the blocking agent for steamflood application is examined here.
Abstract A series of interfacial tension (IFT) measurements versus temperature were carried our at a constant pressure using the Pendent Drop apparatus. The study was conducted with seven different samples of viscous crude oil using as the aqueous phases a source water for water injection, distilled water, and heavy water. The temperatures investigated ranged from ambient 10 160 ยฐC. For two heavy oils if was found that the IFT initially decreased then increased with temperature and for one oil there was only an increase. For all other systems IFT either remained constant or decreased with increasing temperature. To investigate this apparent anomaly of increasing IFT with increasing temperature, a series of experiments were conducted to examine the effect of oxidation of the bitumen and also the effect of intermediate or light-end hydrocarbons which may hare been lost from the heavy crude oil system during the driving process. No just explanation for the increasing IFT was established. In a system where the density difference between the oil and the aqueous phase was from 0.01 to 0.002 gcm, the Pendent Drop maintains its integrity. However it was found that the drop does not have the necessary shape to permit the determination of an accurate tension. Consequently for the heavier crude oils, modified procedures for measuring IFT were examined and are described. To overcome this problem the density difference between the two phases was increased by using heavy water as the aqueous phase. Introduction The interfacial tension between heavy crude oil and injection water under reservoir conditions plays a significant mechanistic role in the process of enhanced oil recovery. This interaction between the oil and water phases in steam flood recovery schemes is a function of temperature, pressure, and composition of both the hydrocarbon and aqueous phases. With highly viscous crude oils, increasing the temperature of the formation is the most significant factor in mobilizing the oil. However, to improve the efficiency of this process, the use of additives such as solvents, high pH control chemicals, or surfactants co-injected with steam, has been shown to enhance the oil recovery. The dominant mechanism in these cases, is a reduction in IFT at the oil/water interface resulting in the mobilization of oil by in-situ emulsification. Both an increase in temperature and the use of certain additives are expected to cause a decrease in the IFT. The purpose of this study was to investigate this expectation for some heavy oils and waters. This study involved the examination of the effect of temperature on the IFT of a number of heavy crude oil and water systems using the Pendent Drop technique. This quantification of the IFT/temperature relationship is important in a number of areas including:the assessment of the application of chemicals in low- and high-temperature enhanced recovery processes. the study of the effect of IFT as it relates to emulsification of oil-in-water or water-in-oil. the establishment of high-temperature IFT relationships associated with thermal recovery mechanisms.
- North America > Canada > Alberta (0.31)
- Europe > Norway > Norwegian Sea (0.25)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.35)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (0.92)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid management & disposal (0.83)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (0.68)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Thermal methods (0.68)
Abstract The reservoir pressure required for the development of a dynamic vaporizing or condensing gas drive is often determined experimentally by what is referred to as the "slim-tube" displacement test. Early work has shown that, provided the displacement is stable, the determination of the minimum miscibility pressure is the only function of the thermodynamic conditions (nature of fluids and temperature). The purpose of this investigation is to verify whether the above condition holds/or conventional tests carried out in flat slim-tube coils. This has been done by examining the effect of tube length and injection rate on the displacement efficiency at various pressures covering the immiscible and multiple-contact miscible displacements. It was found that gravity segregation has an adverse effect on the results, and in the early stage of the displacement, unstable flow occurs for the injection rates studied. These rates are of the same order of magnitude as those considered by other experimenters. Increasing the length of the model, tends to have an over-all stabilizing effect on the results. For short slim-tubes, the usual indicators cannot be trusted to establish the MMP*. The use of longer slim-tubes yield the best estimate of the MMP. Introduction P. Deffrene et al. have shown that the MMP is only dependent On the thermodynamic conditions (nature of the fluids and temperature), if proper care is taken to suppress any unstable phenomenon, namely, viscous fingering and gravity override. They used a vertical displacement, to take advantage of gravity segregation to suppress fingering, provided the rate used was smaller than the critical rate defined as: Equation (Available In Full Paper) The criteria used for MMP estimation is to plot recovery versus operating pressure at gas breakthrough or after 1. to 1.2 pore volumes injection, and the pressure where the curve shows a clear break in slope, will correspond to the MMP. It is evident that the method will be influenced by the macroscopic sweep efficiency of the displacement making it imperative to eliminate the causes for poor sweep, which are: viscous fingering, and gravity override (horizontal systems). However, as pointed out by Orr et al, there is no general consensus as to the experimental procedures or the criteria defining the MMP. They observe that the displacement lengths range from 1.5 m to 25.6 m, flow geometries vary from vertical to flat coils to spirals, and flow velocities vary over nearly two orders of magnitude. The MMP is generally determined on criteria based on recovery at some pore volume injected and/or, on the visual observation of the transition zone in a sight glass. These criteria will be discussed in more detail in a later section. Our experiments were conducted on a flat slim-tube coil apparatus, because it is the most commonly used in the industry. The effect of tube length and injection rate on displacement efficiency, namely, recovery and shape of the effluent gas concentration profile, and consequently their effects on the criteria used for estimating the MMP were examined
Abstract The injection of mixtures of flue gas and Steam has been proposed in conjunction with the development of downhole Steam generators, the Vapor Therm process and the Wet Air Oxidation Boiler. The combined gas-steam injeclioll process may be superior to steam-only injection in terms of improved oil production performance and reduced levels of atmospheric pollution. This paper reviews previous experimental and numerical simulation work related to gas-steam injection and presents the results of an experimental study of steam-flooding with nitrogen Gild carbon dioxide additives. The experiments were conducted in linear porous media which were saturated with a moderately viscous refined oil and water. Several rests involved the injection of slugs of gas followed by steam but the majority used the simultaneous injection of The gases and Steam. It was found that for the systems studied, the addition of the gases to steam resulted in a slight improvement ill over-all recovery bill a marked improvement in the rate of production of oil. Introduction Much effort has recently been directed toward the development of downhole steam generators (DHSG) for use in thermal recovery of heavy oi1. In the high pressure direct-fired DHSG, flue gases from combustion of the fuel are injected into the oil producing formation along with the steam. This type of DHSG has several advantages over conventional surface steam generation including 1) elimination of stack, surface line and wellbore heat losses during injection; 2) reduction of atmospheric pollution; and 3) potential for improved production performance due to the presence of gases which are soluble in reservoir fluids. The elimination of wellbore heat losses by placing the DHSG just above the producing interval extends the depth to which steam may be used to perhaps 1800 metres (6000 feet) from the current limit of 800 metres (2600 feet)HI, Recent field tests of DHSG have demonstrated certain beneficial effects of the reservoir on pollutants: the elimination of particulates, an order of magnitude reduction of NO2, substantial scrubbing of SO2 and a two-fold reduction of Co. A portion of the pollutants remain in solution in residual reservoir liquids and in gas which is trapped in the reservoir. Much of the pollutant material is also recovered in solution in the produced liquids, Soluble gas injection with steam may improve recovery and production performance due to a number of mechanisms including swelling, viscosity reduction, and solution gas drive. Meldau el al,have used numerical simulation to identify the following mechanisms which assisted oil recovery in field experiments of cyclic air/steam stimulation:trapping of gas at saturations up to the critical; increased gas drive of heated oil near the wellbore; movement of heat into upper more viscous oil sands; and greater drawdown due to higher reservoir pressures. In addition to DHSG, two other processes have been proposed for enhanced oil recovery involving surface generation of mixtures of flue gases and steam: the Carmel Energy Vapor Therm Process and the Zimpro-AEC Wet Air Oxidation (WAO) Boiler.
Abstract Emulsions of heavy crude oil-in-distilled water were formed using a rotational turbine mixer with Triton X-100 as an emulsifier. The rheological characteristics of two heavy crude oils and their emulsions were studied using concentric cylinder Gild cone and plate rotational viscometers. The effects of shear rate and temperature on the flow characteristics of distilled water-m-oil emulsions and the effect of shear rate on the flow characteristics of oil-in-distilled water were determined. The results show that emulsions exhibit Newtonian flow behaviour at low dispersed phase concentrations and pseudo plastic behaviour at higher concentrations, In addition, the viscosity is shown to be only slightly time dependent at higher shear rates. It was noted that a large discontinuity in the viscosity occurs at disperse phase concentrations of 30 to 40% Of the distilled water-in-oil emulsions. This may have been caused by a minor inversion of the water-in-oil emulsion to a dual water-ill-oil-in- water emulsion. The viscosity of the dual emulsion would be lower because the water forms the continuous external phase. Introduction In the past emulsion properties and emulsions themselves have only been of minor interest in enhanced oil recovery technology. With the major trendto improved oil recovery schemes., the use of emulsions to increase oil recovery has sparked interest to further understand emulsion behaviour flow properties. Emulsion science has been developed by a range of industries, from paints to cosmetics and from foods such as milk products to pesticides. The rheologic properties and characteristics of emulsions have been of interest because of the many applications of emulsions. The oil producing industry can no longer merely consider emulsions to be dealt with when they occur. Many researchers are now seeking to apply emulsions to improve the recovery of oil. The study of the rheological properties of crude oils and their emulsions was the broad objective of this study. Specific objectives included:The determination of the rheology of both water-in-oil and oil-in-water emulsions of crude oil and distilled water. The demonstration that emulsion viscosity can be dependent on the shear rate because of non-Newtonian behaviour. More specifically, the emulsion can be non-Newtonian at some concentration and Newtonian at other concentrations. Relating the emulsion viscosity as a function of shear rate, temperature and disperse phase concentration. Apparatus and Experimental Procedure; The two heavy crude oils used in this study were: Epping Crude Oil and Cold Lake Crude Oil. The Epping Crude Oil had an API gravity of about 11.8 degrees and viscosity of about 50 000 mPa.s at 21ยฐC (and 1.0 5). The crude oil was proudced in May 1976 and dewatered and dried in February 1978. The long period of storage resulted in an alteration of some of its properties (specifically, aging increased the viscosity of the oil by slow oxidation with air).The original (1976) viscosity measured was 1120 mPa.s at 40ยฐC (and 0.89 s) for the dried crude oil.
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Downhole chemical treatments and fluid compatibility (1.00)
- Facilities Design, Construction and Operation > Processing Systems and Design > Separation and treating (1.00)
Abstract A laboratory study was conducted to determine the recovery of high-viscosity crude oil from natural unconsolidated sand by wate1flooding with a number of chemical solutions. Displacement tests were run using chemical solutions to displace a high-viscosity crude oil from artificial packs of unconsolidated core sand. Results of the displacement tests showed that oil recovery was increased by a number of chemical solutions. Sodium hydroxide in bTi.ne at concentrations less than 0.01 per cent by weight had little effect on recovery as compared to brine floods. Sodium hydroxide concentrations of 0.1 per cent OT greater increased recovery significantly. The interfacial tension between Lloydminster crude oil and various aqueous solutions was greatly reduced by the addition of a number of chemicals to the aqueous solutions. The presence of sodium chloride in the aqueous solution reduced the a1nount of chemical required for the reduction of the interfacial tension between crude oil and the solution to a given level. The reduction in interfacial tension influenced the recovery of oil. The production of a very stable emulsion and evidence of reduced water mobility during displacement tests suggested that emulsification may have occurred within the core. The formation of an emulsion may have increased oil recovery. Introduction THERE ARE large known reserves of heavy oil in Western Canada. However, the nature of the reservoirs and oils involved are such that primary recovery is estimated at 5 to 6 per cent, with a possibility of increasing total recovery to about 10 per cent of the oil in place by means of conventional water-flooding. In order that these recoveries be increased to a more acceptable value) new secondary recovery techniques must be developed. This study represents a continuation of a series of investigations conducted at the University of Alberta into the effect of chemical additives on water-flood recovery from heavy oil reservoirs. It is well known that the preferential wettability of the solid surfaces in porous media influences their relative permeability, capillary pressure and waterflood ability characteristics. These properties can be altered by introducing any one of a variety of liquids which alter the contact angle. However, if a surface is oil-wet, the contact angle (conventionally measured through the denser phase) cannot be reduced below 90 degrees, so that further reductions in adhesion tension and therefore energy requirements for oil displacement can only be realized through reductions in interfacial tension. Reductions in interfacial tension also serve to reduce capillary forces, thereby further reducing the amount of energy required for oil displacement. Similarly, changing a system from an oil-wet to a water-wet state improves the relative permeability to oil and increases the efficiency of the oil displacement process. Several investigators have reported obtaining higher waterflood recoveries from preferentially water-wet systems than from corresponding oil-wet systems. The ability of some oils to preferentially wet silica sand surfaces has been noted and the use of chemicals or "flooding agents" to increase recovery from such sands has been considered by a number of investigators.
Abstract In-situ combustion methods of oil recovery generally involve heat transfer with phase change and chemical reaction coupled with the hydrodynamics of multi-phase flow through porous media. To date, a vast amount of work has been carried out in this area and a. number of successful projects have been reported. This paper examines only a portion of this field. It presents an over-all view of the forward combustion process by reviewing the results of some of the key experimental and theoretical studies and field tests. Introduction ALTHOUGH THE FORWARD COMBUSTION PROCESS may be described by means of an intricate ensemble of a number of individual physical and chemical processes, the over-all mechanism has been initially described simply as follows. The process is initiated by injecting air for a short period, so as to establish a continuous gas phase between the injecting- and producing wells. Once this is accomplished, heat is introduced into the injecting well so as to raise the temperature of the formation in the vicinity of the wellbore. When the formation temperature has been raised sufficiently, the formation oil, in vicinity of the wellbore, is ignited. As air injection continues, the burning gradually progresses from the injecting to the producing well When burning stabilizes, the process may be described by means of a series of zones, as is shown in Figure, 1. In short, this series consists of a? burned zone, a combustion front, a hot water zone, a light hydrocarbon zone, an oil bank and an original or unaltered zone. At the Fifth World Petroleum Congress, Tadema. using the results of recent investigations proposed a more detailed representation of the over-all mechanism, as is shown in Figure 2. In his representation, the series of zones consists of a burned zone, a combustion zone, a multiphase zone, a three-phase zone, an oil bank zone and an original zone. These zones contain air, coke, (steam, gases, hot water and light hydrocarbons). (gases, oil and water), (oil and gas) and original oil, respectively. According to this model, the temperature distribution assume the shape of a heat wave and is characterized by a peak temperature in the combustion zone, a steep front followed by a steam plateau downstream, and a graduate decline upstream. In general, the heat-wave propagation velocity does not appear to be influenced b:v oil or rock type hut is directly related to air flux and oxygen content. That is as air flux and oxygen content are decreased the temperature profile tends to elongate. The Combustion Zone In the multiphase zone, crude oil is vaporized and cracked or carbonized to produce a residuum or coke deposit on the sand surface. This deposit serves as fuel in the combustion zone. Heat is then carried forward by convection by the water resulting from combustion, vaporized formation water hot gases and combustion products. Generally the peak temperature in the combustion zone varies between 700 and 1,000 ยฐF. Combustion itself is believed to occur in two steps.
Abstract A two-dimensional mathematical model was formulated to describe the injection or steam into an oil reservoir assuming that a step-function satisfactorily approximates the actual temperature profile within the permeable sand. The model was applied to a homogeneous isotropic reservoir to calculate the temperature in the surrounding strata and the thermal efficiency of the injection process. For a particular set of reservoir conditions, the comparison of the results with a published analytical solution for the one-dimensional case showed that there exists a particular injection rate and pay thickness below which the one-dimensional heat transfer model may not be valid. A second model was formulated to describe the backflow period. The thermal behaviour of the non-permeable strata was accounted for by dividing the surrounding formation into two sets of semi-infinite concentric cylinders and applying the one-dimensional heat flow equation to each shell. The fluid mechanics aspect was described by applying Darcy's equation under plug-fluid flow conditions. With the exception of viscosity, all physical properties were assumed to be independent of temperature and were calculated at an average temperature. The trend of the results of two example calculations is consistent with that generally observed from pilot tests reported in Western Canada.
- North America > United States (1.00)
- North America > Canada > Alberta (0.47)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Thermal methods (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (0.84)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (0.68)
Abstract A mathematical model was formulated to describe the injection of saturatedsteam down oilwell tubing under constant inlet conditions. The system was divided into three parts, consisting of the fluid, thewellbore and the formation. Each part was considered to be a separate system, with the heat flux across the boundaries acting as the coupling parameter. Thewellbore consisted of a tubing string enclosed by either one or two casingstrings. The heat transfer in the wellbore was considered as steady state. Theheat transfer in the formation was treated as unsteady-state radial conduction, and the fluid flow was described by a modified two-phase flow correlation. The analysis resulted in three equations, two of them implicit, which weresubsequently solved simultaneously on the 7040 computer. The solution did notpresent any convergence problems. Although a complete verification of themathematical model was not possible, the calculated temperature profiles weresimilar in shape to an observed temperature profile. Introduction With the cost of finding and developing high-grade crude reservescontinually increasing, more attention is being focused on the development ofhigh-viscosity or "heavy" oil reserves. As the oil viscosity is highlydependent on temperature, a small increase in reservoir temperature decreasesthe oil viscosity markedly, facilitating increased production rates andultimate recoveries. One of the more popular means of increasing the reservoirtemperature is steam injection. To evaluate the feasibility of a thermalproject, a reasonably accurate estimate of the heat losses from the well bore, the sandface pressure and the sandface quality of the steam would be desirable, if not necessary. As the injection times are generally quite small, steady-state solutions would not be very representative and unsteady-statesolutions are required.