Development Of Heavy Oil Reservoirs Research Articles

Evolution of Acidic Compounds in Crude Oil during In Situ Combustion

In situ combustion (ISC) process has drawn more and more attention in the development of heavy oil reservoirs as a result of its high recovery efficiency. Although numerous studies have been reported that oil properties exhibit significant changes during the combustion process, the reaction mechanisms and evolution of oil components are still not well understood. In this work, the compounds of produced oils collected from a three-dimensional simulated production model (container) at different duration times after combustion being initiated and the original oil were characterized at the molecular level using gas chromatography (GC), gas chromatography–mass spectrometry (GC–MS), and high-field Fourier transform ion cyclotron resonance mass spectrometry (FT-ICR MS). Both aromatic and acidic components were analyzed. The aromatic components showed relatively more stable characteristics than those of acidic components, and no obvious changes in aromatic compound distributions were observed by the positive ion atmospheric pressure photoionization (APPI) FT-ICR MS analysis. Small aliphatic acids were detected in the ISC oils, which were responsible for the high total acid numbers (TANs). The acidic Ox (x = 1–3) compounds, which have major contributions to the increase in TAN, were generated in greater abundances compared to that of the original crude oil. The carbon number distributions of the O1 and O2 classes in the produced oils significantly shifted to a lower carbon number region, with the dominant distribution from 15–40 at the initial state to 10–30 at the longest duration time. The double bond equivalent (DBE) values decreased during the combustion process. The generated acidic O1 components with DBE values less than 4 were also found in negative ion electrospray ionization (ESI) analysis, indicating the oxidation of hydrocarbons to alcohols.

Application and Effect Factors of Artificial Barrier in Heavy Oil Reservoir with Bottom Water

The experience of developing oil reservoir with bottom water indicated that the key technology is to control bottom water coning to extend oil production period with water-free at utmost and to make bottom water drive evenly. Interbed between water and oil beds can curb bottom water coning in production wells and extend oil production period with water-free, then the oil recovery in low water cut period can be greatly enhanced. Artificial barrier, which can control bottom water coning effectively and improve the effect on its growth, is the direction of development on controlling bottom water coning. This paper puts forward a new theoretical calculation equation of barrier pattern. Taking Huan616 reservoir as an example, the results are confirmed by theoretical calculation, indoor physical simulation and numerical simulation. Coning water suppression effect of artificial barrier in the development of heavy oil reservoir with bottom water is also analyzed.

Performance of multiple thermal fluids assisted gravity drainage process in post SAGD reservoirs

Multiple thermal fluids injection process is a new heat-carrier process proposed in recent years as an EOR process for heavy oil reservoirs. Compared with the conventional saturated-steam injection process, it combines the multiple advantages of immiscible and/or miscible gas injection and thermal recovery processes. In this paper, based on the ideas of the multiple thermal fluids injection process and the conventional steam assisted gravity drainage (SAGD) process, a new recovery process, multiple thermal fluids assisted gravity drainage (MFAGD) process is proposed to enhance heavy oil recovery for post SAGD reservoirs. Two 3D gravity drainage experiments (SAGD and SAGD-MFAGD) are first conducted to explore EOR mechanisms of the multiple thermal fluids in heavy oil reservoirs. Subsequently, numerical simulations are performed to match the experimental measurements. Then the EOR mechanisms and the remaining oil saturation distribution are analyzed. Furthermore, the differences between the SAGD, steam-and-gas-push (SAGP) and MFAGD processes are discussed. From a dimensionless scaling analysis for gravity drainage process, lab scale parameters are converted to field scale ones, and a field scale simulation model is developed. Through the analysis and simulation, the reservoir adaptability of the MFAGD process is investigated, and its operation parameters are numerically optimized. Experimental results indicate that a strategic combination of the SAGD and MFAGD processes can tremendously improve the development of heavy oil reservoirs. The MFAGD process can be adopted as a follow-up recovery technique after the SAGD process for heavy oil reservoirs. As its EOR mechanisms, in addition to the conventional thermal recovery mechanisms of steam injection, the results show that heat insulation, energy recovery, gas dissolution, foamy oil and auxiliary well cleanup are all its important mechanisms. In comparison with SAGD, this new process has a higher recovery rate, a lower steam injecting volume and a lower cumulative steam-oil ratio (cSOR). Numerical results also show that the steam chamber from MFAGD is shaped like a liquid drop instead of a conventional inverted triangle from SAGD. The net-to-gross value and formation thickness have a great influence on the performance of MFAGD. It is found that for MFAGD, the optimal steam-gas ratio in the standard conditions is 1:1, the steam injection rate is 200m3/d, and the operation pressure is 3.0MPa for the study reservoir. The MFAGD process will be a potentially important EOR method for post SAGD heavy oil and oil sands reservoirs.

Optimal parameters selection for SAGD and VAPEX processes

Steam Assisted Gravity Drainage (SAGD) and Solvent Vapor Extraction (VAPEX), both of the techniques have been proved to be successful for the exploitation of heavy oil reservoirs. Field development of heavy oil reservoirs requires careful determination of optimal parameters, well locations and control setting of producers and injectors. In recent years, field development decisions based on sensitivity studies have been shifting toward automated optimization. In this paper, we present the optimal parameter selection for SAGD and VAPEX. We performed the search of optimum parameters; the vertical separation between injector and producer, well controls and well locations. All these parameters have been simultaneously optimized to study and compare the performance of both processes. Also, we present an efficient method to constrain horizontal wells to preset minimum well spacing constraints. This method was then applied to constrain the well spacing between different peers of horizontal wells in the SAGD and VAPEX processes. The particle swarm optimization was used as an optimizer to determine the optimum parameters. The results indicated that the method could successfully determine the optimal parameters while satisfying the spacing constraint imposed by the user. The comparison of the results showed the better performance of SAGD over VAPEX process.

The relationship between formation temperature and permeability in a heavy oil reservoir

ABSTRACTIn the process of heavy oil exploitation, formation temperature changes severely, which will cause the deformation of formation skeleton and the redistribution of formation permeability, and then affect the crude oil seepage. On the contrary, the change of formation permeability will change the distribution of temperature field. In order to study the relationship between formation temperature and permeability in a heavy oil reservoir, on the basis of three field coupling mechanisms, the authors adopted a physical simulation experiment to study the effect of formation temperature on the formation permeability, and results show: when the temperature is kept at the same level, the permeability of sample decreases with the increase of effective stress, and the decline rate is bigger at the initial stage, then it will level off gradually. When the effective stress is kept at the same level, the permeability of sample decreases with the rise of temperature. The authors study the effect of formation permeability on the distribution of temperature field through numerical simulation method, and results show that the higher the permeability is, the faster the temperature field will spread; also formation temperature will be higher under the same condition. All achievements have important guiding significance for the effective development of heavy oil reservoir.

Analysis of the Flow Velocity of Heavy Oil Reservoir Flooding Vent Complex Process

With the deepening of the degree of oil exploration and development, as well as the rapid growth of world demand for oil, heavy oil reservoir development is becoming increasingly important in the position in oil exploration. For reserves a great deal of ultra heavy oil reservoir at present, conventional thermal recovery technology is difficult to obtain a good development effect. In this study we use computational fluid dynamics software ANYSY CFX to analyze the impact of horizontal and vertical pressure gradient on the seepage velocity difference..

Feasibility Study on Development of Heavy Oil Reservoir by Steam-Nitrogen Assisted Gravity Drainage

Currently, the primary method for developing extra heavy oil is the steam assisted gravity drainage (SAGD) characterized by high recovery factor and gas-oil ratio. However, in the course of application of this technology, because the whole reservoir needs to be heated to a very high temperature, too much steam is needed, and simultaneously, the loss of heat of reservoir is also increased. For the purpose of exploiting the extra heavy oil more economically, a SAGP technique, the steam and gas push, is put forward in the oil industry world. This paper takes the adding of nitrogen as an example, conducts reservoir engineering theory analysis, numerical simulation study and physical modeling study, and concludes that when adopting SAGP technique, it is unnecessary to increase the temperature of the whole reservoir to a very high value; compared with SAGD, although the cumulative production of SAGP declines to some extent, the steam injection volume is only 68% of that of SAGD, which indicates that SAGP exploitation technique can save steam and thus reduce the production cost compared with SAGD.

The Evaluation of EOR Methods for a Heavy-oil Reservoir With the AHP Method: The Case of Ferdowsi Reservoir

Enhanced oil recovery (EOR) strategies for development of heavy oil reservoirs is a very complex process because it involves a great amount of money and parameters and it is necessary to consider the risk associated with geological, economical, and technological uncertainties. On the other hand the wrong strategies risk time and national capital, especially in Iran. Therefore, it is very important to choose the proper strategy to improve the quality of the results and to accelerate the process. The authors applied the analytic hierarchy process to evaluate five alternatives for EOR of a heavy oil reservoir in one Iran's heavy oil fields. This method helps reservoir management team to structure the fundamental hierarchy model, which is suited for the Ferdowsi reservoir in Iran's situation.

Variation Characteristics of Reservoir Physical Properties after Thermal Recovery in Heavy Oil Reservoirs

With the development of heavy oil reservoirs, it faced a series of problems. Using the theory of thermal-hydrological-mechanical (THM) coupling, a predictive model of reservoir physical properties (RPP) after thermal recovery is established. Based on this model, the changing process of reservoir physical properties is simulated by the method of numerical simulation. The obtained results show that the sand production has a significant influence on RPP. By contrast with rock deformation, it has a smaller influence on RPP. The influence caused by the former is about 5~8 times than latter. During the period of steam injection, resulting from the movement of sand grain and expansion of reservoir, both porosity and permeability of reservoir are on the rise. Due to the sand production and reservoir compression, a reducing tendency is happened in the production period. The changes of RPP in reservoir are huge along the main streamline direction, and it might change because of the presence of high-permeability path.

Improvements of Superheated Steam Stimulation in Secondary Development of Heavy Oil Reservoir

With superheated steam, there is no direct relationship between temperature and pressure, Therefore, at a particular pressure it is possible for superheated steam to exist at a wide range of temperatures higher than that of its saturated steam. The heat transfer coefficient is 1/150-1/250 as much as that of saturated steam during heat transferring, and it takes a relatively long time to cool, during which time the steam is releasing very little energy and transmitted long distances. The mechanisms of superheated steam stimulation are mainly pointed to the performance of crude oil viscosity reduced, flow environment improved, rock wettability changed, oil displacement efficiency improved. Physical simulation shows that oil displacement efficiency by superheated steam is 6-12% higher than that of saturated steam at the same temperature, and under the condition of carrying the same heat, superheated steam enlarged the heating radius by about 10m, oil steam ratio increased by 0.7. Superheated steam stimulation was put into Kazakstan’s heavy oil reservoir after two cycles of saturated steam stimulation. The average daily oil production was 2-4 times that of saturated steam stimulation, which improved heavy oil production effectively. The secondary heavy oil thermal recovery by superheated steam stimulation applied in marginal heavy oil reservoirs achieved satisfactory effect.

Technology Focus: Heavy Oil (March 2012)

Technology Focus The rapid growth in interest and in development activities related to unconventional oil and gas resources, including heavy oil, is clearly evident throughout the industry. One outcome has been a tremendous increase in the number of SPE papers written this past year on various topics associated with development and recovery optimization of heavy-oil reservoirs. Another is that petroleum-engineering departments at many more universities worldwide are actively engaged in teaching courses and performing research related directly to viscous- and/or heavy-oil recovery. One topic in particular has gained more attention: development and application of enhanced thermal-recovery methods that use various solvents as a means to improve recovery and to reduce operating costs significantly relative to conventional thermal projects. Continued knowledge development in this subject area through a combination of reservoir-scale physics and chemical-process analysis, simulation-capability advancement, laboratory testing, and field-piloting work is needed to enable operators to design and implement these methods effectively and commercially, especially for viable development of thinner, lower-quality heavy-oil reservoirs. One synopsis paper and a reading paper were selected to provide further insights regarding the potential and the challenges associated with the use of solvent-recovery techniques in such applications. The other papers were chosen to illustrate the variety and significance of the challenges operators may encounter in assessing and/or pursuing the development of heavy-oil reservoirs under different settings and conditions. These include various problems that had to be dealt with during testing of a heavy-oil well in an offshore location; the many planning issues, design tradeoffs, and performance considerations associated with the sequencing and conversion of a heavy-oil-field development from cold to hot production; the difficulties experienced in planning and conducting pilot operations in a high-viscosity oil field overlain by thick permafrost in the Russian Arctic; and the ability to achieve adequate recovery with steaming of fractured carbonate reservoirs. Recent literature also describes several interesting technology developments, modeling studies, and field-trial activities related to the use of in-situ combustion and electrical-heating methods as alternative heavy-oil-recovery techniques. Several additional papers present results from investigations of CO2 injection into heavy-oil or bitumen reservoirs to achieve both improved oil recovery and greenhouse-gas sequestration, while many others describe new developments and/or field experiences involving waterflooding and polymer flooding of heavy-oil reservoirs. The many papers written on these topics can be sourced through OnePetro. Recommended additional reading at OnePetro: www.onepetro.org. SPE 146671 A Semianalytical Approach for Estimating Optimal Solvent Use in a Solvent-Aided SAGD Process by Subodh Gupta, SPE, Cenovus Energy, et al. SPE 149917 Approaches to Development of High-Viscosity Oil Fields in Arctic Conditions by Example of the Russkoe Field by I. Edelman, OJSC TNK-BP Management, et al. SPE 150692 A New Perspective on Tracking Energy Transfer in SAGD Derived From 3D Numerical Field-Scale Simulations by C.C Ezeuko, SPE, University of Calgary, et al. SPE 144524 Recovery Mechanism of Steam Injection in a Carbonate Reservoir by Guo-Qing Tang, SPE, Chevron, et al. SPE 148966 Analysis of the First CHOPS Pilot for Heavy-Oil Production in Kuwait by Tirtharenu Sanyal, Kuwait Oil Company, et al. SPE 148917 Effect of Methane Coinjection in SAGD—Analytical and Simulation Study by Jyotsna Sharma, SPE, University of Calgary, et al.

Flow Characteristics of Heavy Oil through Porous Media

Performance of flowing through a capillary and porous media for different kinds of heavy oil at different temperatures have been studied by experiments in this article. It shows that the heavy oil containing asphaltene-colloids displays yield-stress rheology (Bingham fluids). The displacing pressure difference increases linearly with the increase of the flow rate. However, the start flowing pressure is different for different heavy oil samples at different temperatures. The higher the temperature is, the lower pressure the heavy oil needs to flow; and when the temperature is high enough, the start flowing pressure equals zero. The minimum temperature at which the start flowing pressure equals zero is called converting temperature. Also, the more viscous the heavy oil is, the higher the converting temperature will be. An exponential relationship of yield stress and temperatures has been obtained for different kinds of heavy oils by the experiments of heavy oil flowing through a capillary. A logarithmic relationship of converting temperatures and the dead oil mobility at 50°C has been obtained for heavy oil through different porous media. When a temperature is lower than the converting temperature, the start flowing pressure gradient decreases as a log tendency with the increase of temperature when different heavy oils are flowing through different porous media. For the existence of the start flowing pressure gradient, the heavy oil production rate is different from that for the Newton fluid and it is adverse to the development of heavy oil reservoirs. The test results are favorable to choose the reasonable temperature for heavy oil transportation running in a pipe or well bore and also determine the temperature limitation for different production rates for a specific well sample. It is also important for improving the development effect efficiently.

Analysis of Heat Loss of Ground Pipeline of Thermal Production Oilfield

Steam stimulation is one of the main methods used in heavy oil reservoir development. How to inject high temperature and high dryness steam is a key factor to enhance heavy oil recovery. It is significant to evaluate heat transfer of steam pipeline and optimize thermal insulation layer for heavy oil exploitation. Based on fluid mechanics, heat transfer theory, considered phase change, mathematical model to calculate heat transfer and heat loss of steam pipeline was derived. Using COMSOL Multiphysics, a finite element based program for simulating unlimited multiphysics and single physics applications, the author simulated heat transferring in ground steam pipeline and analyzed the effect of thermal insulation layer. From the simulation results, it was known that, (1) Along with the pipeline distance increases, the steam dryness decreases, the decrease rate decreases with the distance increases. (2) At the same transmission distance, the bigger the thermal insulation layer thickness is, the smaller the heat loss of the steam is. The heat loss of steam transmission mainly center on the first half pipeline. (3) With the thickness of thermal insulation layer increases, the heatloss declines. After the thickness of thermal insulation layer increases 90 mm, increasing the thickness has no obvious effect on reducing the heat loss. So, it is suggested that the thermal insulation layer thickness should be 75-80mm.

A Review on Thermal Enhanced Heavy Oil Recovery from Fractured Carbonate Reservoirs

Heavy oil in Middle East fractured carbonate reservoirs account for 25-30% of the total oil in place in the region. Production of heavy oil from such reservoirs is thought to play an important role in the future of the ever-growing world\'s energy consumption in which Iran\'s recoverable heavy oil is more than 85 billion barrels. The offshore Ferdows field in Iran is reportedly on the order of 30 billion barrels of oil and holds perhaps the greatest promise to add significant future carbonate heavy oil production within the region. With depletion of conventional petroleum reserves and increase of hydrocarbon fuel demand, there is no doubt that there will be a tremendous demand on the development of heavy oil reservoirs in the coming decades. Despite its strategic importance, recovery of heavy crude from fractured carbonate reservoirs has found limited applications due to the complexity of such reservoirs. As most of the oil is stored in matrix due to its higher storage capacity than fracture network, reservoir development plans will aim at maximizing the matrix oil recovery. For reservoirs with high recovery factor, minimizing matrix residual oil saturation is a critical issue to extend the life of the reservoir. For reservoirs with low recovery factor, accelerating the production rate is more vital. For each of these reservoir types, different Enhanced Oil Recovery (EOR) methods should be considered and implemented accordingly. In this study, a comprehensive review is conducted to figure out the feasibility of heavy oil recovery from fractured carbonate reservoirs by use of Cyclic Steam Stimulation (CSS), Steam injection, In-Situ Combustion (ISC), Steam Assisted Gravity Drainage (SAGD), Vapor Extraction (VAPEX) and Expanding Solvent-Steam Assisted Gravity Drainage (ES-SAGD).

Application of neural network combined genetic algorithm to rank the development priority of heavy oil reservoirs

PurposeThe purpose of this paper is to present a new approach for selecting the good heavy oil reservoirs to develop preferentially, which can avoid the huge economical loss resulted from wrong decision.Design/methodology/approachA new method of ranking the development priority of heavy oil reservoir is present, in which the neural network is applied for the first time to acquire reservoir parameters' weights through training samples and the genetic algorithm is used to optimize the joint weighs of neurons in case that neural network falling into local minimum. Additionally, the paper establishes subordinate function of every parameter. Eventually, comprehensive evaluation values of all heavy oil reservoirs are obtained.FindingsThe method can ensure the veracity and creditability of the parameters' weights, avoid the randomicity brought by experts.Research limitations/implicationsAccessibility of the data of many heavy oil reservoirs is the main limitation.Practical implicationsA very useful and new method for the decision makers of heavy oil reservoirs development.Originality/valueThe new approach of ranking the development priority of heavy oil reservoir based on the neural network and the genetic algorithm. The paper is aimed at the leaders who manage the development of heavy oil reservoirs.

Heterogeneity Impact on SAGD Process Performance in Mobile Heavy Oil Reservoirs

The increasing oil demand and the significant amount of heavy oil/bitumen reserves will motivate a huge effort on the development of heavy oil reservoirs in the next decades. Within this framework, Steam Assisted Gravity Drainage (SAGD) is a very promising technique to produce heavy oil from thick and high permeability reservoirs. The small scale field tests conducted up to now highlighted the influence of heterogeneities on the development of the steam chamber involved in SAGD. This work presents a numerical investigation of the effects of heterogeneity on SAGD performance when applied to produce mobile heavy oil. A set of reservoir models is randomly generated with 0, 10, 15 and 20% of shale and a statistical analysis is performed to quantify the impact of shale distribution on oil production and SAGD efficiency. It is shown that the influence of shale baffles depends on their locations relatively to well pairs, the most detrimental ones being located between the injector and producer. In addition, we observe that 1/2, 1/3 and 1/4 only of the cumulative oil volume produced for the homogeneous model after 3 years of SAGD process are recovered when shale proportions are 10, 15 and 20% and that CSOR evolves from 2 for the homogeneous model to 3 for the models with 20% of shale.

A Simplified Methodology on Selection, Operation, and Optimum Design of Steam Drive Reservoirs

Abstract Steam drive is a viable, proven technology for the development of heavy oil reservoirs. Prior to implementing the steam drive process, a prescreening strategy to evaluate the recovery potential is valuable. Meanwhile, the effect of operating conditions, the design techniques to satisfy specific operating conditions, and the management of any subsequent infill drilling programs in light of the steam drive history are all critical to successful steam drive projects. Based on numerical simulation and field cases, this paper provides some critical strategies and a simplified methodology for evaluating the steam drive process. Based on reservoir physical properties, a pre-screening formula is proposed for computing recovery factors that allow preliminary economic analyses to be performed. It is shown that a successful steam drive project must satisfy the following four operating criteria:Steam injection rate is 1.6 to 1.8 m3/(d.ha.m);Production injection ratio is greater than or equal to 1.2;Bottom hole steam quality is greater than 40% and,Reservoir fluid pressure is maintained below 5 MPa. A design methodology is also provided, which can provide information on the most effective well pattern (5-spot, inverted 7-spot, and inverted 9-spot) and well spacing in order to satisfy the above four criteria. The sensitivity of the methodology to the injectivity/productivity estimates is also discussed. Introduction The steam drive process is an effective technology to develop heavy oil reservoirs. Most steam drive projects operated over the last two decades have achieved satisfactory oil recovery relative to their reservoir properties. From the late 1980s to the early 1990s, more than 10 steam drive pilots were operated in China. Unfortunately, most of them did not achieve their anticipated recovery factors for the following reasons(1):Some key parameters assumed prior to initiating the pilot were not realistic. For example, the steam drive pilot of Du I Group in Du 163 Block applied 5-spot 4 ha well patterns and a steam injection rate of 140 m3/d-CWE. However, the liquid production capacity of a single well was only 40 – 50 m3/d. This low production/injection ratio resulted in poor pilot performance.Some heavy oil reservoirs were simply not suitable for the steam drive process. For example, Well Group 3 –4 –032 and Well Group 3 –4 –76 in Gaosheng oilfield are over 1,600 m deep. At this depth, the bottomhole steam quality remained well below the target of 60% due to excessive heat loss in the injection tubing and the high reservoir pressure.Ineffective operation of the field pilots. The productivity of some pilots was reduced by formation contamination during drilling and completion. In some pilots, the liquid level in production wells was very high indicating poor production optimization and, in most cases, the steam quality was too low to achieve high recovery factors. Based on a theoretical study and field case studies, this paper provides critical suggestions on the following four aspects of the steam drive process:What types of heavy oil reservoirs are suitable for a steam drive project?

Simulation of Sand Production in Unconsolidated Heavy Oil Reservoirs

Previous research on sand production prediction focused on when sand will be produced during depletion based on some mechanics analyses, but the amount of sand production was ignored. Recently, more and more researchers are focussing on the simulation of heavy oil sand production processes. For an unconsolidated heavy oil reservoir which employs sand production to enhance production, the amount of sand production is of great importance, because too much sand production may cause near wellbore instability, while too little sand production may not maximize well productivity. In view of this, based on both fluid flow modelling and reservoir mechanics concepts, a coupled heavy oil/sand particulate flow/reservoir elasto-plastic deformation model is used to simulate sand production, oil production, and reservoir deformation. With this model, we can determine an optimum flow rate which will not cause near wellbore instability while maximizing well productivity.Introduction. Heavy oil sand production as an important production enhancement measure has been used in the primary development of heavy oil reservoirs in Canada for a long time.The production of sand may lead to the change of formation flow-related parameters such as permeability, porosity and mechanical parameters such as cohesion, and it also causes near wellbore stress redistribution. Thus, sand production is a very complicated process involving both fluid flow and geomechanical problems. In order to simulate the effect of sand production and productivity enhancement, simulation of the physical process needs to be done. Because of the long history of cold production, the simulation of cold production is becoming mature and a lot of excellent work has been done by experts in Canada and elsewhere around the world(1–5).Wang(1) developed a model to predict sand production in a heavy oil reservoir in Frog Lake at Lloydminster, Canada. It is believed that reservoir depletion induces stress concentrations around the wellbore, and large drawdown causes a foamy oil zone, in which large drawdown and seepage forces are created which causes sand production. A fully coupled geomechanical, foamy oil flow model was developed. Sand production is assumed to start when the effective radial stress is equal to the tensile strength. Later Wang(2) developed a coupled reservoir-geomechanical model to simulate the enhanced production phenomena in both heavy oil reservoirs (Northwestern Canada) and conventional oil reservoirs (North Sea). It is believed that the production enhancement is contributed:by the reservoir porosity and permeability improvement after a large amount of sand is produced, andby the higher mobility of the fluid due to the movement of the sand particles. Once the reservoir formation yields plastically, loose sand particles can be generated.Sand production has been postulated as a critical condition when the effective radial stress reaches the tensile strength or when the plastic strain reaches the critical plastic strain. Recently, Papamichos et al.(3) and Stavropoulou et al.(4) also provided their model to simulate sand production. Later Papamichos et al.(5) applied successfully this model to interpret sand production from a North Sea reservoir.

Simulation of Sand Production in Unconsolidated Heavy Oil Reservoirs

Abstract Previous research on sand production prediction focused on when sand will be produced during depletion based on some mechanics analyses, but the amount of sand production was ignored. Recently, more and more researchers are focussing on the simulation of heavy oil sand production processes. For an unconsolidated heavy oil reservoir which employs sand production to enhance production, the amount of sand production is of great importance, because too much sand production may cause near wellbore instability, while too little sand production may not maximize well productivity. In view of this, based on both fluid flow modelling and reservoir mechanics concepts, a coupled heavy oil/sand particulate flow/reservoir elasto-plastic deformation model is used to simulate sand production, oil production, and reservoir deformation. With this model, we can determine an optimum flow rate which will not cause near wellbore instability while maximizing well productivity. Introduction Heavy oil sand production as an important production enhancement measure has been used in the primary development of heavy oil reservoirs in Canada for a long time. The production of sand may lead to the change of formation flow-related parameters such as permeability, porosity and mechanical parameters such as cohesion, and it also causes near wellbore stress redistribution. Thus, sand production is a very complicated process involving both fluid flow and geomechanical problems. In order to simulate the effect of sand production and productivity enhancement, simulation of the physical process needs to be done. Because of the long history of cold production, the simulation of cold production is becoming mature and a lot of excellent work has been done by experts in Canada and elsewhere around the world(1–5). Wang(1) developed a model to predict sand production in a heavy oil reservoir in Frog Lake at Lloydminster, Canada. It is believed that reservoir depletion induces stress concentrations around the wellbore, and large drawdown causes a foamy oil zone, in which large drawdown and seepage forces are created which causes sand production. A fully coupled geomechanical, foamy oil flow model was developed. Sand production is assumed to start when the effective radial stress is equal to the tensile strength. Later Wang(2) developed a coupled reservoir-geomechanical model to simulate the enhanced production phenomena in both heavy oil reservoirs (Northwestern Canada) and conventional oil reservoirs (North Sea). It is believed that the production enhancement is contributed:by the reservoir porosity and permeability improvement after a large amount of sand is produced, andby the higher mobility of the fluid due to the movement of the sand particles. Once the reservoir formation yields plastically, loose sand particles can be generated. Sand production has been postulated as a critical condition when the effective radial stress reaches the tensile strength or when the plastic strain reaches the critical plastic strain. Recently, Papamichos et al.(3) and Stavropoulou et al.(4) also provided their model to simulate sand production. Later Papamichos et al.(5) applied successfully this model to interpret sand production from a North Sea reservoir.

A Comparative Laboratory Analysis of Steamflooding With Horizontal Wells In Heavy Oil Reservoirs With Bottom Water Zone

Abstract Two laboratory 3D scaled models were developed to compare the performance of steam flooding in reservoirs having bottom water zone with the application of different well configurations. One of the models was triangular, designed to represent 1/12th of a 7-spot pattern and the other was a square that corresponds to ?th of a 5-spot pattern in the B. Kozluca field in Turkey. Nine experiments were conducted by using the triangular model with or without bottom water zone, whereas four experiments were conducted with the rectangular model. The well configurations were changed during the course of experiments to determine their effects on oil recovery. Bottom water thicknesses were changed to see the effects on oil recovery. The physical properties of crushed limestone and crude oil (12.4 ° API) mixture were kept constant during the experiments. Steam was injected through a vertical injection well in both models. Strings of thermocouples were used to observe 3D temperature distribution inside the models. The maximum oil recoveries were obtained by placing the horizontal producers along the hypotenuse of the triangular model and the diagonal of the rectangular model, respectively. Besides, in both cases, the same well configuration provided better oil recovery than any other well configurations even in the presence of a bottom water zone. Oil recoveries decreased with increase in the thickness of the bottom water zone. SOR increased in the presence of bottom water. Introduction The increasing demand of non-renewable fossil fuel energy and the gradual depletion of conventional crude oil reservoirs led to the development of heavy oil reservoirs. The most efficient means to recover oil from these heavy oil reservoirs is thermal recovery method in which heat is applied to the reservoir. The application of heat in the form of hot water, hot gases, and steam reduces the viscosity of these heavy oils upon which, a more economic recovery is readily obtainable. These days, the thermal recovery method is widely known and applied worldwide for secondary and tertiary recoveries. Of all the thermal recovery methods, steam injection is the most popular method. Following steam injection into any heavy oil reservoir, the viscosity, specific gravity and flow resistance of the fluid in the reservoir changes, resulting in oil production increases. The reduction in the viscosity as a result of an increase in the temperature, facilitates the movement of the heavy oil. Advantages of Horizontal Wells Because of their numerous advantages, horizontal wells have gained attention in the petroleum industry(1,2).Horizontal wells provide larger contact within a reservoir and hence, eliminate the need for multiple vertical wells to acquire same reservoir drainage. Recovery is two to five times greater than that of a non-stimulated vertical well.In the case of a reservoir where vertical penetration of the formations would be uneconomical, drilling of the horizontal well would render a sufficient well bore opening and a possibility of a more economic recovery.Horizontal wells in the reservoir where coning of water and gas are predominant provide a better oil recovery while minimizing the coning effects.