Cold Production Of Heavy Oil Research Articles

Factors, Mechanisms, and Kinetics of Spontaneous Emulsification for Heavy Oil-in-Water Emulsions.

In challenging reservoirs where thermal recovery falls short, cold or chemical oil recovery methods are crucial. Spontaneous emulsification (SE), triggered by gentle disturbance, significantly enhances oil recovery. In elucidating SE mechanisms and kinetics, SE processes via direct contact between oil and aqueous phases without stirring were conducted. The effects of temperature, emulsifier concentration, pH, NaCl concentration, and the oil-to-water ratio on SE were investigated through droplet size analysis and turbidity measurements. Furthermore, the emulsification mechanism and derived emulsification kinetics based on turbidity data were obtained. The results underscore the feasibility of SE for oil-water systems, reducing viscous and capillary resistances without agitation. The emulsified oil mass increased with the temperature, pH, and aqueous-to-oil phase volume ratio while decreasing with the NaCl concentration. In this study, for GD-2 crude oil, the optimal emulsified oil amount occurred at a betaine surfactant (BetS-2) emulsifier concentration of 0.45%. Microscopic photo analysis indicated narrow particle size distributions and small droplets, which remained stable over time under various experimental conditions. A combined SE mechanism involving ultralow interfacial tension, interfacial turbulence due to Marangoni effects, and "diffusion and stranding" due to in situ emulsifier hydrophilicity, was speculated. Additionally, an analogous second-order kinetic equation for SE was proposed, indicating exceptional correlation with calculated and experimentally measured values. This study offers theoretical insight for enhancing oil recovery in chemical and cold production of heavy oil in oilfields.

Study on the kinetics of formation process of emulsion of heavy oil and its functional group components

Enhanced oil recovery (EOR) by in situ formation of oil-in-water emulsion in heavy oil cold production technology has received growing interest from the petroleum industry. We present an experimental study of emulsification of model oils prepared by heavy oil and its functional group compositions dissolved into toluene brought into contact with a surfactant solution. The effects of functional group composition, emulsifier concentration, temperature, pH and stirring speed on the emulsification rate of heavy oil was investigated. A second-order kinetic model characterizing the temporal variation of conductivity during the emulsification has been established. The results show that acidic and amphoteric fractions exhibit higher interfacial activity, larger emulsification rate constant and faster emulsification rate. With the increase of emulsifier concentration, the emulsification rate constant increase to the maximum value at a concentration of 0.05 mol/L before decreasing. Temperature increase benefits the emulsification rate and the activation energy of the emulsification process is 40.28 kJ/mol. Higher pH and stirring speed indicate faster emulsification rate. The heterogeneity of emulsions limits the accuracy of dynamic characterization of the emulsification process and the determination method of emulsification rate has always been controversial. The conductivity method we proposed can effectively evaluates the emulsification kinetics. This paper provides theoretical guidance for an in-depth understanding of the mechanism and application of cold recovery technology for heavy oil.

Factors and Kinetics Related to the Formation of Heavy Oil-in-Water Emulsions

Oil-in-water emulsions provide an essential contribution to enhanced oil recovery by acting as oil displacement and conformance control systems. However, the dominant factors affecting their emulsification and kinetics are unclear. The emulsification rate is usually defined in terms of changes in the torque, conductivity, or particle size over time, which results in inaccurately calculated emulsified oil amounts. Therefore, the effects of temperature, pH, and NaCl concentration on the emulsified mass and droplet sizes of aqueous emulsions of Jin8-7 and Chen373 oil with octadecyl amine ethoxylate ether as an emulsifier were investigated. The results showed that the formation of oil-in-water emulsions of Jin8-7 and Chen373 under different conditions occurred via a two-stage mechanism: rapid emulsification and emulsion maturation. The emulsified oil mass rapidly increased during the rapid emulsification period and plateaued during the emulsion maturation period. This indicates that the emulsified oil mass largely depended on the short rapid emulsification period. It was also found that increasing the temperature and pH were more conducive to the emulsification of Chen373 oil with a high viscosity and high asphaltene content. The optimal NaCl concentration was determined to be 2% and 4% for Chen373 and Jin8-7 oil, respectively, based on the emulsification mass during the rapid emulsification period. The droplet size decreased first and then increased during the emulsification process under most experimental conditions. A second-order kinetics model for emulsification was proposed, in which the evolution of emulsified oil mass calculated with time agreed with the experimentally measured values. This study can provide theoretical guidance for the implementation of chemical cold production of heavy oil in oilfields.

Soft Movable Polymer Gel for Controlling Water Coning of Horizontal Well in Offshore Heavy Oil Cold Production.

Horizontal well water coning in offshore fields is one of the most common causes of rapid declines in crude oil production and, even more critical, can lead to oil well shut down. The offshore Y oil field with a water cut of 94.7% urgently needs horizontal well water control. However, it is a challenge for polymer gels to meet the requirements of low-temperature (55 °C) gelation and mobility to control water in a wider range. This paper introduced a novel polymer gel cross-linked by hydrolyzed polyacrylamide and chromium acetate and phenolic resin for water coning control of a horizontal well. The detailed gelant formula and treatment method of water coning control for a horizontal well in an offshore field was established. The optimized gelant formula was 0.30~0.45% HPAM + 0.30~0.5% phenolic resin + 0.10~0.15% chromium acetate, with corresponding gelation time of 26~34 h at 55 °C. The results showed that this gel has a compact network structure and excellent creep property, and it can play an efficient water control role in the microscopic model. The thus-optimized gelants were successively injected with injection volumes of 500.0 m3. The displacement fluid was used to displace gelants into the lost zone away from the oil zone. Then, the formed gel can be worked as the chemical packer in the oil–water interface to control water coning after shutting in for 4 days of gelation. The oil-field monitoring data indicated that the oil rate increased from 9.2 m3/d to 20.0 m3/d, the average water cut decreased to 60~70% after treatment, and the cumulative oil production could obtain 1.035 × 104 t instead of 3.9 × 103 t.

Dispersion Mechanism of Viscosity Reducer and Evaluation of Displacement Experiment for Cold Production of Heavy Oil

Dispersion Mechanism of Viscosity Reducer and Evaluation of Displacement Experiment for Cold Production of Heavy Oil

Behaviors of Foamy Oil Flow in Solution Gas Drive at Different Temperatures

The role of foamy oil flow in the cold production of heavy oil in a solution gas drive has been extensively studied in recent years. In this study, solution gas drive tests were performed in micromodels and sandpacks to investigate not only the behaviors of foamy oil flow at different temperatures but also the effect of temperature on displacement efficiency. The micromodel tests indicated that three flow states existed with the solution gas drives at 54.0 and \(100.0\,^{\circ }\hbox {C}\), which were an oil phase flow, a foamy oil flow and an oil–gas two-phase flow. The micromodel test at \(150.0\,^{\circ }\hbox {C}\) showed a continuous gas phase, while the two-phase oil–gas flow was formed after the oil phase flow. The sandpack test results showed that foamy oil can improve the performance of a solution gas drive at temperatures below \(120.0\,^{\circ }\hbox {C}\). Unfortunately, the behavior of the foamy oil flow was not readily observed in the sandpack test at \(150.0\,^{\circ }\hbox {C}\). The results of this study also showed that there is an optimum temperature at which the highest oil recovery can be obtained in the solution gas drive and that the relative permeabilities of the gas and oil can be estimated from the sandpack test results. When the gas saturation is less than the cutoff gas saturation, the relative permeability ratio of the gas and oil at a higher temperature is higher than that at a lower temperature; the mobility ratio at \(100.0\,^{\circ }\hbox {C}\) was also shown to be lower than that at 54.0 and \(150.0\,^{\circ }\hbox {C}\).

Non-classical Nucleation Model for Cold Production of Heavy Oil

Abstract We examine the gas bubble nucleation phenomenon encountered in extra heavy oil during cold production. The nucleation model described in this work is based on so-called non-classical nucleation. Using this method, we show mesoporous cavities could be at the origin of the nanobubble trapping mechanism. The results obtained show this physical approach tends to demonstrate the pre-existence of gas bubbles in these crevices (surface roughness). The physics of capillarity used here is based on traditional Laplace's law and an original disjoining pressure expression. We test for several wettabilities in our mathematical model. The first configuration envisaged is for oil-wet rocks, although the cavity is assumed to be gas-wet. Water wettability is considered a second time, taking into account a precursor water film between the rock and the entrapped bubbles. The mix of these two configurations could represent nucleation in a global mixed-wet porous media. However, we show in the first part of this article that water presence does not affect the initial bubble radius. Nevertheless, a bubble growth model developed in the second configuration shows that bubble confinement could play an important role on gas bubble nucleation and the early first steps of its development. Introduction Macroscopic nucleation mechanisms have been the subject of many studies over the last decades because of both its fascinating underlying physics and its technological importance in many domains. The physics of gas bubble generation and growth in supersaturated solutions is a confusing subject in the literature. Jones et al.(1) proposed a classification system for the kinds of nucleation that occur experimentally. They define mechanistically four types of nucleation and place the specific forms of nucleation into a better defined context. Several authors concluded that the heterogeneous nucleation form is the most plausible mechanism in porous media. Nevertheless, homogeneous or heterogeneous nucleation on molecularly smooth surfaces requires a very high level of supersaturation. During a depletion experiment with heavy oil in porous media, the supersaturations reached are low, so another type of nucleation has to be envisaged. The opposite of the classical bubble nucleation theory which requires very high levels of supersaturation, is one where the activation of the pre-existing gas cavities needs very low levels. Therefore, to study the nucleation phenomenon in heavy oil we assume the pre-existence of trapped gas bubbles in contact with the supersaturated liquid. Lubetkin(2) focused on this and claimed that theory predicts a need for a much higher supersaturation to cause bubble nucleation than is found experimentally. Moreover, the theory predicts that the nature of the liquid influences the conditions required for nucleation and experimental works show a strong influence with the chemical nature of the gas. Considering this, we try to take into account the influence of the physical and chemical properties of the liquid and gas in equilibrium in the crevice and develop a detailed net analysis of the various existing forces. Most previous work relates to spontaneous bubble formations which occur after a rapid decompression of a liquid solution initially saturated with dissolved gas molecules.

Viscosity Behavior of Foamy Oil: Experimental Study and Modeling

Heavy oil cold production is faced with the foamy oil phenomenon: while extracted, a heavy crude oil is submitted to a depletion that can induce the formation of dispersed gas bubbles and makes it appear as a foam. This situation results in a change of the flow properties of the live oil that is still debated: correlations predict a decrease or an increase in the gas bubble-dispersed oil viscosity with the gas volume fraction. We attempted to improve the understanding of the foamy oil behavior through rheological measurements. A live oil was depleted inside the pressure cell of a controlled stress rheometer. The occurrence of bubbles was checked and visualized with x-ray scanning experiments. Viscosity was continuously measured using oscillatory and continuous tests. This particular experimental approach allowed us to successfully study the rheological behavior of a foamy oil in relationship with the two main parameters, which are the composition and the viscosity of the crude oils. A theoretical model describing the viscosity of a foamy oil has been established. It takes into account both first-order kinetics of appearance and release of bubbles in oil and a basic suspension model. Results from this model are in agreement with experimental data obtained from different heavy crude oils.

VAPEX, Warm VAPEX and Hybrid VAPEX - The State of Enhanced Oil Recovery for In Situ Heavy Oils in Canada

Abstract VAPEX, warm VAPEX and hybrid VAPEX rely on a combination of mass and heat transfer to reduce the heavy oil's viscosity sufficiently for it to flow via gravity drainage to the production well. In the last couple of years, many combinations of vapour extraction and steam-assisted gravity drainage have been proposed for the in situ recovery of heavy oil and bitumen. The question still remains; which technique (VAPEX, warm VAPEX, hybrid VAPEX and/or SAGD) produces more oil with better sweep efficiencies? This paper attempts to define and compare the various enhanced heavy oil recovery techniques, including different solvent choices. The pore-scale mechanisms are identified, key advantages and disadvantages given and the results from simple laboratory experiments are compared to better direct he investigation into the in situ recovery of heavy oil and bitumen. The solvents and solvent mixtures (in combination with non-condensable gases and/or steam) are analyzed based on their physical properties at laboratory and reservoir conditions and the role they play at the pore-scale. Introduction Canada's heavy oil reserves are found in western Canada, mainly in Alberta and Saskatchewan. The geographic location of the reserve is indicative of the quality of the oil based on geology. The oil deposit is generally shallower and the oil's viscosity higher (with a lower ºAPI density) the further east and north it is found. The oil found at the surface and below, is in thin shallow sandstone and unconsolidated sand. The porosity ranges from 26 – 32% and the permeability from 1,200 – 7,500 mD(1). The current producing fields are found at the surface to a maximum depth of 800 – 1,000 m, have a reservoir temperature from 4 to 40 ºC and the oil's viscosity is from 500 cP to greater than one million. Cold production of heavy oil is possible, but production rates are low. Sand is often produced with the oil (not necessarily a disadvantage), water cuts are generally high and recovery factors marginal. Cold production is still a logical choice for fields with lower viscosity oil. Otherwise, in situ heavy oil and bitumen can be produced using enhanced oil recovery techniques (EOR). Canada is the world leader in developing EOR techniques for heavy oil production. New techniques and a combination of techniques are constantly being investigated and compared where the ultimate goal is to maximize oil recovery. Steam-assisted gravity drainage (SAGD), cyclic steam stimulation (CSS), in situ combustion and vapour extraction (VAPEX) are all EOR possibilities. Combinations of VAPEX and SAGD are also being explored and reexamined. This paper strives to give the history of VAPEX, warm VAPEX and hybrid VAPEX, and then focuses on comparing and analyzing the different methods, highlighting advantages and disadvantages, as well as pore-scale mechanisms in VAPEX. The History of VAPEX, Warm VAPEX and Hybrid VAPEX VAPEX or vapour extraction is the process of injecting a solvent into a heavy oil reservoir (through an upper horizontal well) to reduce the viscosity of the heavy oil via mass transfer.

Development Status of a Metal Progressing Cavity Pump for Heavy-Oil and Hot-Production Wells

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 97796, "Development Status of a Metal Progressing Cavity Pump for Heavy-Oil and Hot-Production Wells," by J.-L. Beauquin and C. Boireau, Total E&P, and L. Lemay and L. Seince, PCM Pompes, prepared for the 2005 SPE International Thermal Operations and Heavy Oil Symposium, Calgary, 1–3 November. Progressing cavity pumps (PCPs) often are used for cold heavy-oil production because of their adaptability to viscous and abrasive fluids. However, for thermal recovery, a standard PCP is not adaptable because the elastomer of the stator, the heart of the pump, cannot withstand fluid temperatures higher than 160°C. An all-metal pump, avoiding the elastomer weakness, has been developed. Validation tests began in early 2005 using extra heavy crude with temperatures up to 200°C, pressure up to 75 bar, and flow rates up to 260 m3/d at 350 rpm. The flow-rate range will be as high as 1000 m3/d. Introduction Most oil fields require some type of artificial lift at some point in time. When sufficient gas is available, gas lift may be a viable lift method because it involves relatively low-cost well interventions and tolerates numerous flow constraints, such as high gas content, gas slugging, sand production, and high temperature. When a gas lift system is inadequate, too expensive, or not possible, the artificial-lift needs challenge downhole pump capabilities and features. Some wells are able to use hydrodynamic pumps such as centrifugal, helicoaxial, or hydraulic-jet pumps because of the very high volume to be lifted. However, these pumping technologies are expensive. Most pumped wells are equipped with positive-displacement pumps, which can be adapted to changing conditions of pumped fluid. Beam- and rod-driven plunger pumps can be adapted to handle many types of fluids because they are simple, robust, and well understood. However, in heavy oil, rod failure is the most common limitation, which leads to limiting the well production, which, in turn, worsens the risk of sand settling in the pump. Also, slow closure of traveling and standing valves is a cause of poor efficiency in viscous mixtures. Pumping in horizontal or highly deviated wells also limits the plunger downstroke because it is powered by the driving part of the rod-string weight. Thermal production methods generate fluctuating inflow properties that change rod-failure causes and reduce the run life of the system. During the 1980s, rotating-rod-driven PCPs were developed for oilfield applications. PCPs are used for viscous oil, horizontal wells, and sandy production. Rod-driven PCPs are used for cold pro-duction of heavy oil and often are used in conventional mature fields as a cheaper lift method than beam pumps. The standard PCP stator is made of elastomer, which is the source of most of the pump's limitations including fluid temperature and gas and aromatics content.

Improving the State of the Art of Western Canadian Heavy Oil Waterflood Technology

Abstract Heavy oil waterfloods have been operated in Saskatchewan and Alberta for up to 50 years, yet remarkably little discussion of the theory or operation of heavy oil waterflooding has been published. Conventional waterflood theory is based on assumptions that are not encountered in heavy oil reservoirs, and those theoretical and operational experiences should not be substituted. This editorial draws upon information from the relatively small number of significant theoretical and field discussions of Western Canadian heavy oil waterflooding available in the public domain to establish that the "state of the art," including proposed production mechanisms, prediction of performance, and improvement of performance, is extremely limited. Introduction An immediate challenge is deciding which waterflooded pools to include under the "heavy oil" umbrella, as imprecise definitions of heavy oil are used by both government agencies and waterflood operators. Definitions have at times been based on API gravity (a value of = 20 ° API is sometimes used), but often the driving criterion is geography. If a waterflood is located in an area near heavy oil cold production, it is sometimes simply classified as heavy oil, and given to a heavy oil group to operate. Emphasis on an oil-gravity-based definition of heavy oil is convenient, but unfortunate, as it de-emphasizes oil viscosity even though viscosity has repeatedly been shown to be a controlling parameter. Aversion to a viscosity-based definition for heavy oil may be due to occasional problems obtaining consistent heavy oil viscosity measurements(1, 2), and confusion about whether available viscosity values were collected using dead oil, live oil, or something in between. In stark contrast to this general neglect of viscosity data in heavy oil waterflood papers and articles, the most common informal statement about heavy oil waterfloods is, "you can't have a successful heavy oil waterflood if the dead oil viscosity is greater than" a particular value. Values in the 1,000 to 2,000 cp dead oil viscosity range (at reservoir temperature) are often cited as "the limit," but no study establishing a limit appears to exist. Searching the literature for information can be misleading. "Heavy oil" is often used in the title of waterflood articles because conventional oil waterflood technical staff consider oil with viscosity in the range of 3 to 10 cp (much lower than the hundreds to thousands of cp oil more typically waterflooded in Western Canada) to be heavy oil. The technology of Canadian heavy oil waterflooding likely started as conventional oil waterflood theory. It has evolved in a generally empirical manner, and in some ways is still more "art" than "science". The mobility ratio is so adverse that the "flood" process is likely over very quickly. The subsequent process is circulating water which brings enough oil with it for the process to be economic. This much longer "post-flood" period of Western Canadian heavy oil waterfloods is optimized using empirical methods that are often done differently by each oil company, engineer, pumper, etc. The result is a very limited written state of the art.

Pressure Pulsing at the Reservoir Scale: A New IOR Approach

Abstract Laboratory tests initiated in January 1997 demonstrated clearly that periodic, large-amplitude, low-frequency strain excitation of porous media leads to large flow enhancements. Based on these results, a new liquid flow enhancement technology for reservoirs was formulated, and a successful full-scale field experiment was executed in early 1999. Other field projects in 1999 through 2001 waterfloods in heavy oil cold production wells with sand influx confirmed the expectation that pressure pulsing, properly executed, increases oil production rate at low cost. The first trial showed that periodic application of large amplitude, liquid-phase pressure pulses increased oil production rates, decreased water-oil ratio, and increased the percentage of sand produced, even without large-scale injection. Though experience to date is in heavy oil, the process is general and will work in all porous media that have interconnected pore space. Furthermore, the method works in single-phase and two-phase liquid saturated cases, although the presence of large amounts of free gas is detrimental. Based on the field and laboratory work, and considering the nature of the physical processes, it appears likely that pressure pulsing will also help reduce coning and viscous fingering instabilities, help overcome capillary blockages, and result in more total oil recovery over time. Introduction In the oil industry, progress in production technologies is most commonly based on empirical discoveries, and only later followed by attempts to develop a consistent physical theory to explain, analyse, and predict field behaviour. This is the case for all processes, such as CHOPS (Cold Heavy Oil Production with Sand), SAGD (Steam Assisted Gravity Drainage), and so on. Often, a fully rigorous physical theory remains elusive (e.g., for oil-gas-water-sand slurry flow in CHOPS production), and practice is refined through empirical models, physical reasoning and trial and error. However, the results obtained from laboratory and field research and development in pressure pulsing over the past five years were initially predicted from a new, more rigorous physical theory for porous media flow. The new theory(1) is a more complete system of equations for dynamic behaviour of interconnected multiphase porous media (matrix-liquid, including matrix-water-oil systems). It was developed by considering all relevant pore-scale physical processes (micro scale), followed by rigorous volume averaging to scale the physics up to the scale of a representative elementary volume (REV) that can statistically represent mesoscopic behaviour (cm scale). The theory is therefore consistent with the laws of thermodynamics in component phases at the pore scale, and leads to large-scale thermodynamic relationships (equations) in which porosity is found to play a fundamental thermodynamic role, similar to that of temperature in single-component systems. In other words, porosity must be treated as a basic thermodynamic variable in porous media(2). Furthermore, induced dynamic variations in porosity are responsible for the observed flow rate enhancement effect. The physical theory also dictates the experiments required to determine the parameters that arise in the equations(3). A slow dynamic wave called the porosity dilation (or porosity diffusion) wave is predicted(4).

3D Physical Model Studies of Downhole Catalytic Upgrading ofWolf Lake Heavy Oil Using THAI

Abstract THAI-"Toe-to Heel Air Injection" is an integrated horizontal process for the recovery and in situ upgrading of heavy crude oil. In addition to thermal upgrading, further upgrading can be achieved by emplacing a catalyst layer around the horizontal producer well, in effect creating a downhole reactor. A series of six catalytic tests was performed in two 3D combustion cells to investigate the degree of upgrading achievable with 10.5 ° API gravity Wolf Lake oil. The main factors investigated were the type of HDS catalyst (NiMo, CoMo), extrudate or crushed catalyst, and catalyst loading. The results of these tests show that the basic process is very stable over a 10-hour period, maintaining an average peak combustion temperature of 500 to 600 °C. Thermal upgrading alone (THAI) achieved nearly 10 points increase in the API gravity of the produced oil. This was increased by a further 4 to 7 ° API using the catalytic process. This indicates that it may be possible to convert a heavy crude oil to almost a light oil product in a one-step in situ reservoir process. The oil recoveries were consistently very high, at around 85% OOIP, with the produced oil having a viscosity as low as 10 mPa's at 20 °C, (i.e., mPa's). The process demonstrated robust stability when changes in the air injection rate were made, and there was also an oil productivity gain when operating at a low water air ratio, WAR < 1.0. Introduction Unlike conventional light oil, the production of heavy oil is uch more difficult, mainly due to its high viscosity at reservoir conditions. When the oil viscosity is very high (> 10,000 mPa.s) in the reservoir, the oil is virtually immobile. Cold production of heavy oil only recovers a small proportion of the original oil in place, typically about 5% to 10%. Improved Oil Recovery (IOR) or Enhanced Oil Recovery (EOR) methods are required to increase the oil mobility and improve heavy oil production. Steam injection, vapour extraction and in situ combustion (ISC) are the three main techniques, achieving oil recoveries of more than 50% OOIP. However, expensive surface upgrading processes are required to upgrade the produced heavy oil in order to satisfy refinery feedstock specifications. ISC is achieved by burning a small fraction of the oil in the reservoir to release the combustion reaction energy between the injected oxygen and hydrocarbons. This greatly increases the temperature in the reservoir, mobilizing the heavy oil so that it can be displaced. The high temperatures (> 500 °C) created during the in situ combustion process promote thermal cracking of the heavier components of the oil, which results in thermal upgrading. This advantage is normally not captured in the conventional ISC operation using vertical-injection and vertical-production wells (VIVP), or other conventional well patterns. This is because the thermally upgraded oil first has to bank-up in the downstream cold region before it reaches the producer well.

Proposed Air Injection Recovery of Cold-Produced Heavy Oil Reservoirs

Abstract This concept paper explores the potential applications of air injection (in situ combustion) as a follow-up to cold production of heavy oils. Cold-produced fields are ideal potential candidates for air injection due to the significant resource that remains at the economic limit of cold production, and because wormhole- type channels are present in the depleted reservoir. The authors propose steaming the depleted reservoir for a short period of time to collapse the wormholes, thus creating high permeability heated channels. Reservoir ignition and air injection would follow, with the heated channels providing a flow path for the mobilized oil to reach the production wells. The steam/combustion combination would be highly effective in thin reservoirs, where extended steam injection is uneconomic. Additionally, this process addresses the three technical causes for failure in heavy combustion projects: ineffective ignition, inadequate air injection rates, and temporary plugging of the formation due to blockages caused by high liquid saturations. An overview of cold heavy oil production and heavy oil by in situ combustion is provided, as well as a detailed discussion of the proposed process. Introduction Cold Production in Western Canadian Heavy Oil Regional Sands Western Canada contains extensive heavy oil and bitumen deposits, as is shown in Figure 1. Early primary production of this resource using reciprocating pumps in vertical, directional, or slant wells was only economic in the Lloydminster Block; thus, most of the existing geologic studies are for this area(1–3). Following the development of progressing cavity (PC) pumping technology in the 1980s, cold production from these wells (vertical, directional or slant) was expanded rapidly to several additional areas, including Frog Lake, Elk Point, Lindbergh, and portions of Cold Lake and the Primrose Block. This exploitation methodology provides a large percentage of the produced oil volume for most Western Canadian heavy oil producers; in fact, some producers use only this method. Most cold production of heavy oil has been conducted in regional sands from the Lower Cretaceous Mannville Group (see Figure 2). Stratigraphic nomenclature varies locally, but, in general, most Lloydminster area regional sand cold production is from the Sparky and Waseca sands, while most of the Frog Lake, Elk Point, and Lindbergh cold production is from the Cummings.Regardless of the nomenclature, from a reservoir engineering perspective, these sands are characterized as being relatively thin, clean, with high porosity and permeability, and containing high saturations of heavy oil(4). Figure 3 is a plot of the estimated distribution of oil in place vs. sand thickness for the Lloydminster area, and Table 1 describes regional sand properties. Bottom water and edge water are common features, and a significant fraction of the wells in this region become uneconomic due to rapid water influx. Despite continued efforts to improve PC pump-based cold production technology, current methods generally leave 80 to 95% of the OOIP behind at the economic limit. This is a large oil-in-place target for follow up EOR processes; however, the cold production process appears to have strongly altered reservoir conditions from their original state.

Foamy-Oil Flow

Foamy-oil flow is a non-Darcy form of two-phase flow of gas and oil encountered in many Canadian and Venezuelan heavy-oil reservoirs during production under solution-gas drive. Unlike normal two-phase flow, which requires a fluid phase to become continuous before it can flow, it involves flow of dispersed gas bubbles. This paper is aimed at acquainting the readers with this type of flow and its role in heavy-oil production. The paper starts with a discussion of what the term foamy-oil flow means and how it evolved. Then a brief review of the Canadian field practices is presented. This is followed by a discussion of the pore-scale mechanisms involved and the interplay between capillary and viscous forces. A discussion of the strengths and weaknesses of various mathematical models proposed for numerical simulation of this type of flow is also included. The paper ends with a brief discussion of issues that remain unresolved.

Cold Production of Heavy Oil (June 2000)

This article is a synopsis of paper SPE 58773, "Global Experiences and Practice for Cold Production of Moderate and Heavy Oil," by C.A. Ehlig-Economides, SPE, and B.G. Fernandez, SPE, Schlumberger, and C.A. Gongora, U. of Houston, originally presented at the 2000 SPE International Symposium on Formation Damage Control, Lafayette, Louisiana, 23-24 February.

Measurement of Slurry Viscosity In Cold Production

Abstract The falling ball viscometer method was used to measure the viscosity of bitumen and sand mixtures. The viscosity of the slurry was measured over a range of concentrations, but with emphasis on higher concentrations, a regime which is believed to be representative of sand concentration in wormholes during cold production of heavy oil. Non-Newtonian behaviour was observed at very high sand concentration. Introduction In developing cold production technology, it is essential to understand the flow behaviour of slurries, suspensions of sand grains in bitumen and water, and their geomechanical behaviour near the transition towards sand. The objective of these experiments is to elucidate the subject by studying the slurry viscosity as a function of porosity. Shear viscosity of a fluid, as a measure of the rate of dissipative transverse momentum transfer due to shear (see, for example, Landau, et al.)(1), is known to be increased by increasing concentration of sand suspensions in the fluid. At very low concentration, the relative viscosity, defined as the ratio of the mixture to the fluid viscosity, increases linearly with concentration(2). At higher concentration, the relative viscosity increases further and non-linearly due to stronger hydrodynamic interactions between sand grains. At even higher concentrations, direct grain-grain contacts become much more frequent, and hence the transverse momentum transfer becomes much easier. In addition, collision induced grain rotations become more frequent, so that a larger amount of linear momentum is transferred to angular momentum of sand grains, leading to higher viscosity and non-Newtonian behaviour at high shear(3). In this regime the sand grains are in discontinuous contact with one another and we expect a sharper increase in relative viscosity for small decreases in porosity. The upper boundary to this regime corresponds to the transition from a slurry to a saturated sand. At the boundary between these two regimes, the contacts are continuous and a sand grain matrix exists. This concentration corresponds to the "maximum porosity" of the sand grains, which for many sands is typically about 0.45. For a saturated sand there exists a narrow range of concentrations (porosities) within which fluid behaviour may be observed. This can occur at porosities between the "maximum porosity" and the "critical porosity" when shear stresses are applied rapidly to the sand. As the matrix collapses, pore pressures are increased and effective stresses are decreased. If the mobility of the pore fluid is sufficiently low, the effective stresses can be reduced to zero and the sand loses all frictional strength and behaves as a fluid. This behaviour is often referred to as "liquefaction." Many experimental, theoretical and numerical works for hard sphere suspensions have been conducted at relatively high porosities(4–9). However, very few experimental and theoretical works have been done at lower porosities, especially near the "maximum porosity." Furthermore, in the low porosity regime, the relative viscosity could strongly depend on sand grain size distribution and their characteristic shapes. Experimental Techniques Treating the slurry mixture as a single phase fluid, we applied a falling sphere method(10) to determine the relative slurry viscosity.

Cold Production of Heavy Oil From Horizontal Wells in the Frog Lake Field

Summary Texaco Canada Petroleum Inc. (TCPI) has successfully conducted a 10-horizontal well primary production pilot project at Frog Lake, Alberta, Canada. The gravity of the heavy oil ranges from 10 to 14°API, and the oil viscosity ranges from 20,000 to 50,000 cp. These 10 wells were completed in the Lower Waseca formation (one of five prospective formations in the field) and were produced by use of a coproduction of sand and oil from the reservoir at ambient temperatures, known as cold production. These wells were very successful, with most wells displaying productive capabilities in excess of 100 B/D. Based on the technical success of the 10-well pilot, a long-term staged development plan was established to resolve some technical challenges identified by the 10-well project. These challenges include reduction of operating costs and improvement of artificial lift and well reliability. As part of the development plan, over 70 horizontal wells have been drilled and production has peaked at 3,000 BOPD. This paper summarizes the history of the Frog Lake field, completion and production techniques for the pilot project, and some of the operational and technical challenges encountered. A field-wide development strategy and potential for enhanced oil recovery (EOR) are also discussed.

Emerging Technologies For SAGD Drilling And Production

Abstract SAGD, as originally conceived, consists of two parallel horizontal wells, one drilled directly above the other. Steam is injected into the upper well, forming a steam chamber. The heavy oil or bitumen is heated, reducing its viscosity, then drains by gravity, along with the condensed steam, to the lower well. Several other variants exist, including vertical injectors, and single well SAGD. Conventional, aggressive, heavy oil production methods have been labeled "poor reservoir management." In general, 80% of the reservoir energy is expended to produce 20% of the oil in the reservoir. "80/20 Rule"(1). SAGD stands out as an enticing and economically viable development method for operators holding heavy oil and tar sand properties worldwide, even in the current climate of lower heavy oil prices. Recoveries of 55 to 80% OOIP are possible, compared with 5 to 15% for conventional recovery methods, and 18 to 30% for enhanced thermal recovery methods. SAGD production rates of 200 to 1,400 bbl/day have been recorded compared with 0 to 100 bbl/day for non-thermal recovery in the same fields. Both factors combine to achieve production cost reductions of 30% or more. Drilling and completion costs generally run around 20% of the total cost of the project. "SAGD is very, very profitable when applied in the right reservoir." The challenge for SAGD technology lies in finding the right reservoir. This challenge holds true whether SAGD technology is applied to undeveloped areas of the reservoir, or when SAGD is used to clean out oil left behind by less efficient recovery processes. SAGD History 1978 - Imperial Oil drilled the first Hz SAGD well in Canada at Cold Lake. 1987 - AOSTRA lead the way in proving out the concept of twin well SAGD by drilling three 50 m SAGD pairs from a horizontal mine tunnel at the UTF site near Fort McMurray. 1993 - Surface drilled SAGD well pairs. Two well pairs were drilled for Shell Canada at Peace River, and one for Amoco at Wolf Lake. 1995 - First commercial scale SAGD project. CS, now Pan Canadian Resources, drilled and completed three well pairs at Senlac, Saskatchewan. 1998 - Sperry Sun Drilling Services has successfully drilled 44 SAGD well pairs worldwide to date. Technological Advances With conventional SAGD, large quantities of steam are required for production. By injecting approximately 1% of a noncondensable gas, along with the steam, steam requirements are drastically reduced.Laboratory experiments indicate a reduction in steam requirements on the order of 25% (2). An industry funded research project is currently underway involving eight companies and GravDrain Inc. Drilling and Production Issues With cold production of heavy oil, 1,000 m horizontal sections are common and multilateral wells with up to 8,000 m of horizontal section exist. However, with SAGD, horizontal lengths of more than 500 m have proven difficult to manage for two reasons. If product lifting cannot keep up with production, SAGD efficiencies are drastically reduced because hot water, being less viscous than oil, is produced preferentially. Second, establishing a uniform steam chamber in pairs longer than 500 m has proven difficult.

Cold Production of Heavy Oil (October 1997)

This article is a synopsis of paper SPE 37545, "Cold Production of Heavy Oil From Horizontal Wells in the Frog Lake Field," by W. Huang, SPE, and B. Marcum, SPE, Texaco Inc., and M. Chase and C. Yu, Texaco Canada Petroleum Inc., originally presented at the 1997 SPE Thermal Operations & Heavy Oil Symposium held in Bakersfield, California, 10-12 February.