Decrease In Oil Saturation Research Articles

In-situ CT study on the effect of cyclic gas injection and depletion exploitation on the phase behavior of fractured condensate gas reservoirs

Using subterranean rock cores as samples, the impact of depletion exploitation and cyclic gas injection on the occurrence and dynamic utilization of condensate oil and the damage to reservoirs were studied. Initially, the internal pore structure of the rock core was analysed using computer tomography (CT), followed by depletion and cyclic gas injection experiments, with in-situ CT scanning of the samples. The results indicate that under different fracture apertures, condensate oil exhibits wave flow and slug flow states. The production effectiveness of cyclic gas injection is significantly superior to depletion exploitation production, with condensate oil saturation decreasing by over 30%. During cyclic gas injection, fractures serve as the main flow channels, with condensate oil being extracted first. In cyclic gas injection, the most significant effect is seen during the first injection, with a decrease in oil saturation of around 3%. Subsequent injections show decreases of approximately 1% and 0.5% in oil saturation respectively. As the gas injection volume increases, the extent of cumulative production rate improvement also gradually increases; however, once the injection volume reaches the reservoir pressure, the rate of cumulative production rate improvement will gradually decrease. These findings provide technical support for optimizing the development mode of condensate gas reservoirs, clarifying the seepage law of condensate oil and gas, and providing technical support for the efficient development of fractured condensate gas reservoirs.

Visualization Experimental Study on In-Situ Triggered Displacement Mechanism by Microencapsulated Polymer in Porous Media

Summary Polymer flooding in deep reservoir profile control presents challenges in balancing injectivity and effective mobility control. To address this, we propose a solution by utilizing a microencapsulated polymer that can be easily injected and thickens over time. However, limited research has been conducted on the flow characteristics and the impact on oil mobilization by such profile control agents. In this study, we approximately simulated the time-varying flow process of microencapsulated polymer through in-situ triggered experiments at high temperature and pressure. The flow characteristics and oil displacement mechanism of the microencapsulated polymer under different trigger times were analyzed, and the displacement efficiency during the triggered viscosity enhancement process in porous media was quantitatively evaluated. The experimental results reveal that microencapsulated polymer exhibits a dual mechanism of near-wellbore reservoir particle temporary plugging and deep formation consistency control mechanisms. The transient aggregation of capsule particles alters the flow path, intensifying after expansion. The interaction between the microcapsule particles and the partially released polymer further enhances the resistance-enhancing property of the solution. The viscosity-enhanced microencapsulated polymer fluid improves the displacement efficiency. Microscopic oil displacement and coreflooding experiments resulted in a decrease in oil saturation of 39.5 and 18.33%, respectively. This study provides valuable microscopic insights into the flow behavior and oil displacement performance of microencapsulated polymer, offering essential guidance for optimizing oil reservoir extraction strategies.

Influence of pore structure heterogeneity on channeling channels during hot water flooding in heavy oil reservoir based on CT scanning

Hot water flooding is an effective way to develop heavy oil reservoirs. However, local channeling channels may form, possibly leading to a low thermal utilization efficiency and high water cut in the reservoir. The pore structure heterogeneity is an important factor in forming these channels. This study proposes a method that mixes quartz sand with different particle sizes to prepare weakly heterogeneous and strongly heterogeneous models through which hot water flooding experiments are conducted. During the experiments, computer tomography (CT) scanning identifies the pore structure and micro remaining oil saturation distribution to analyze the influence of the pore structure heterogeneity on the channeling channels. The oil saturation reduction and average pore size are divided into three levels to quantitatively describe the relationship between the channeling channel distribution and pore structure heterogeneity. The zone where oil saturation reduction exceeds 20% is defined as a channeling channel. The scanning area is divided into 180 equally sized zones based on the CT scanning images, and three-dimensional (3D) distributions of the channeling channels are developed. Four micro remaining oil distribution patterns are proposed, and the morphology characteristics of micro remaining oil inside and outside the channeling channels are analyzed. The results show that hot water flooding is more balanced in the weakly heterogeneous model, and the oil saturation decreases by more than 20% in most zones without narrow channeling channels forming. In the strongly heterogeneous model, hot water flooding is unbalanced, and three narrow channeling channels of different lengths form. In the weakly heterogeneous model, the oil saturation reduction is greater in zones with larger pores. The distribution range of the average pore size is larger in the strongly heterogeneous model. The network remaining oil inside the channeling channels is less than outside the channeling channels, and the hot water converts the network remaining oil into cluster, film, and droplet remaining oil.

Study on the influence of physical interlayers on the remaining oil production under different development modes

Abstract Using the complex stratigraphic structure model, we study the changes in remaining oil on the millimeter scale in different structural parts during the different water flooding development methods. According to the actual geological structure characteristics of the oil layer, We designed and produced the meter-level experimental model, which ensures the similarity between the model structure and actual oil layer structure. The recovery rate of the primary water flooding stage is 10.36%. The stage recovery rate addition of the change flow direction stage is 7.85%. The final recovery rate is 41.36%. The physical interlayer structure has an influence on the oil saturation change in the nearby layers. The oil saturation reduction value is highest in the left part of layer 3 in the primary water flooding stage, the reduction range is 24.81%. There are 2 parts and 1 part where the oil saturation decreases by more than 10.0% in the second boost flooding stage and the change flow direction stage, respectively.

Coreflood Tests to Evaluate Enhanced Oil Recovery Potential of Wettability-Altering Surfactants for Oil-Wet Heterogeneous Carbonate Reservoirs

Summary Oil-wetness and heterogeneity are two main factors that result in low oil recovery (OR) by waterflood in carbonate reservoirs. The injected water is likely to flow through high-permeability regions and bypass the oil in the low-permeability matrix. In this study, systematic coreflood tests were carried out in both “homogeneous” cores and “heterogeneous” cores with a wettability-altering surfactant. The homogeneous coreflood tests were conducted to evaluate surfactant retention, as well as to compare tertiary surfactant flooding with secondary surfactant flooding. The heterogeneous coreflood test was proposed to model bypassing in low-permeability matrix during waterfloods, and dynamic imbibition of surfactant into the low-permeability matrix. Surfactant retention results suggest that retention increases as initial oil saturation decreases. The retention of selected surfactant in the target reservoir cores was measured to be within a range of 0.07–0.12 mg/g-rock, which is economically acceptable. The results of homogeneous coreflood tests showed that both secondary waterflood and secondary surfactant flood can achieve high OR (>50%) from relatively homogeneous oil-wet cores. A shut-in phase after the surfactant injection resulted in a surge in oil production, which suggests that enough time should be given for wettability alteration by surfactants. The results of heterogeneous coreflood tests showed that more oil is bypassed in the tighter matrix by waterflood if the permeability is higher in the flooded layer and this bypassed oil is the target for the wettability-altering surfactant floods. Slow wettability-altering surfactant injection leads to imbibition into bypassed regions. When the oil-wet carbonate reservoirs have large unswept regions after waterflood, wettability-altering surfactants can significantly improve OR if enough time is given for imbibition.

Pore-Scale Investigation of Microscopic Remaining Oil Variation Characteristic in Different Flow Rates Using Micro-CT

The main means of secondary oil recovery is water flooding, which has been widely used in various oilfields. Different flow rates have a great impact on the recovery ratio and the occurrence of remaining oil. Scholars have carried out extensive research on it, but mostly on the macro scale, and research on the three-dimensional micro scale is also limited by accuracy and a lack of accurate understanding. In this paper, micro-CT and core displacement experiments are used to intuitively show the occurrence state of remaining oil under different flow rates. Through a series of quantitative image processing methods and remaining oil classification methods, the occurrence characteristics of remaining oil under different flow rates are systematically evaluated and studied. The results show that: (1) As the displacement rate increases, the remaining oil saturation decreases (61%; 35%; 23%), but the remaining oil is more evenly distributed along the slice; (2) Two lower displacement speeds (0.003 mL/min; 0.03 mL/min) can reduce the volume of huge oil clusters under oil-saturated conditions, and the highest displacement speed (0.3 mL/min) can completely break up large oil clusters into small oil droplets. At the same time, the shape factor of the oil clusters also gradually increases; (3) The proportion of continuous remaining oil volume decreases, and the proportion of discontinuous remaining oil increases. Discontinuous remaining oil is the main production target of EOR; (4) After water flooding, the microscopic remaining oil is more inclined to the middle and corner parts of the larger pores.

A comprehensive model for simulating supercritical water flow in a vertical heavy oil well with parallel double tubes

At present, there is no research on parallel double pipe injection of supercritical water. The research on the process of SAGD supercritical water injection is insufficient. This paper first established a mathematical model of parallel twin-pipe injection supercritical water pipe flow. On this basis, the SAGD supercritical water injection development numerical model was established using numerical simulation software, and the variation characteristics of the temperature field, crude oil viscosity field and oil saturation field in the reservoir were analyzed. The main conclusions obtained are as follows: (a) the high temperature area first developed from the lower part of the vertical well. (b) After 150 days, the temperature in the reservoir gradually increased. (c) When the injection time reaches 210 days, the viscosity of the heavy oil between the vertical wells has been sufficiently reduced. (d) Condensed water occupies a lot of pore space, resulting in a decrease in oil saturation.

Effect of Displacement Pressure on Oil-Water Relative Permeability for Extra-Low-Permeability Reservoirs.

The oil–water relative permeability is an important parameter to characterize the seepage law of fluid in extra-low-permeability reservoirs, and it is of vital significance for the prediction and evaluation of the production. The pore throat size of extra-low-permeability reservoirs is relatively small, and the threshold pressure gradient and capillary pressure cannot be negligible. In this study, the oil–water relative permeability experiments with three different displacement pressures were carried out on the same core from the extra-low-permeability reservoir of Chang 4+5 formation in Ordos basin by the unsteady experimental method. The results show that the relative permeability of oil increases, while the relative permeability of water remains unchanged considering the capillary pressure and oil threshold pressure gradient compared with the JBN method. As the displacement pressure enlarges, the relative permeability of oil and water both increases; the residual oil saturation decreases, therefore the range of the two-phase flow zone is improved. Moreover, the isotonic point of water–oil relative permeability curves moves to the upper right region, and the reference permeability improves as well with the increasing pressure.

Novel Method for Inverted Five-Spot Reservoir Simulation at High Water-Cut Stage Based on Time-Varying Relative Permeability Curves.

After large-scale and long-term waterflooding, reservoir physical properties such as the pore throat structure and rock wettability may change. In this paper, the relative permeability curves under different water injection volumes through core-flood experiments were used to characterize the comprehensive changes of various reservoir physical properties at high water-cut stage. The novel concept of “water cross-surface flux” was proposed to characterize the cumulative flushing effect on the reservoir by injected water, and a novel method for inverted five-spot reservoir simulation at high water-cut stage based on time-varying relative permeability curves was established. From the relative permeability curves measured through two cores from the X oilfield under different water injection volumes (100, 500, 1000, 1500, and 2000 PV), it is found that with the increase of injected water volume, the two-phase co-flow zone becomes wider, the water permeability under residual oil saturation increases, and the residual oil saturation decreases. A waterflooding core model was established, simulated, and verified by the method proposed in this paper. It is found that using time-varying permeability curves for simulation, the highest oil recovery factor (61.58%) can be obtained with injected water volume up to 2000 PV, and the purpose of improved oil recovery (IOR) can be achieved by high water injection volume, but the increment is only approximately 10%. Besides, a waterflooding model of an inverted five-spot reservoir unit based on the X oilfield was also established, simulated, and analyzed. Simulation results have shown that no matter which set of core permeability curves measured from 100 to 2000 PV is directly used alone, the oil recovery factor will be simulated inaccurately. The findings of this study can help in better understanding the quantitative description of the oil recovery changes with time-varying reservoir physical properties in high water-cut reservoirs during waterflooding.

Two-phase bitumen/water relative permeability at different temperatures and SAGD pressure: Experimental study

The heavy oil or bitumen trapped in subterranean formations in Canada and North America can be effectively produced and recovered using thermal enhanced oil recovery (TEOR) techniques, especially steam assisted gravity drainage (SAGD) processes. Heating the formation to a high temperature greatly reduces the oil viscosity, which increases the oil mobility in the reservoir. In the SAGD process, the steam injected through a long horizontal well creates a steam saturated zone, called steam chamber, around the well that gradually expands laterally and vertically within the reservoir. The edge of the growing steam chamber is where the oil is displaced by the steam. There is a large temperature gradient in the oil drainage zone with steam temperature at the edge of the steam chamber and close to the original reservoir temperature on the other side of the drainage zone. The fluid flow behavior, which is controlled by relative permeability, can be sensitive to the temperature in this transition zone. The objective of this study was to investigate the impact of temperature on two-phase bitumen/water relative permeability of sand over a wide range of temperature from 70 to 220 °C.In the present study, isothermal displacement experiments were conducted with an advanced experimental rig under the confining pressure of 1400 psi using Athabasca bitumen, deionized water, and clean silica sand at six different temperatures. All experiments were repeated to ensure that the results are repeatable and reliable. The JBN (Johnson, Bossler and Neumann) method was used to obtain the two-phase relative permeability. The effect of temperature on relative permeability for the bitumen system was found to be substantial and should be accounted for in simulation of SAGD processes. The endpoint water relative permeability can increase by two orders of magnitude in going from the reservoir temperature to the steam temperature. The endpoint oil relative permeability also increases, albeit more modestly and the residual oil saturation decreases. Besides the relative permeability tests, contact angle and IFT measurements at high-temperature, high-pressure conditions were conducted to evaluate the fluid-fluid and rock-fluid interactions and examine any changes in wettability. According to the contact angle results, the wettability of system was water-wet and shifted toward strongly water-wet at higher temperatures. In addition, the IFT displayed a decreasing trend with temperature and reached the minimum value of 18 mN/m in the temperature range of 125–155 °C.

A new experimental method for measuring the three-phase relative permeability of oil, gas, and water

For tertiary oil recovery, the gas drive is often implemented after water flooding. The three-phase flow phenomenon of oil, gas, and water exists during the process of gas injection. The three-phase relative permeability should be measured to further study the flow characteristics of oil, gas, and water in porous media. In this work, the steady-state flow method is adopted to establish a combined experimental method based on the principle of relationship between resistivity and water saturation, and the principle of on-line CT scanning is used to measure the three-phase relative permeability. The relative permeability of oil, gas, and water is measured under different saturation histories, including the water alternating gas flooding, in which water saturation decreases, oil saturation decreases, and gas saturation increases, as well as gas alternating water flooding, in which water saturation increases, oil saturation decreases, and gas saturation decreases. The experimental results show that in a water-wet core, the relative permeability of water is a function of its own saturation, and its isoperms are straight lines. The relative permeability of oil and gas phase is affected by their saturation and other phase saturations. In an oil-wet core, the isoperms of oil, water, and gas are convex to the point of 100% their own saturation, which means the relative permeability of oil, gas and water depend on all the three phase saturations. The saturation histories influence the isoperms of the three phases differently. Compared with the two-phase flow, the three-phase flow is more complex. This new experiment provides an approach and theory for the study of three-phase seepage laws in the gas drive.

The effect of gas-wetting nano-particle on the fluid flowing behavior in porous media

The effect of gas-wetting on the liquid-blocking effect near a wellbore region is significant. Here, we functionally modified nano-silica particles with a size of approximately 40nm each by using a fluorosurfactant and obtained a super gas-wetting nano-silica particles, which could improve the contact angles of brine and hexadecane from 23° and 0° to 152° and 140°, respectively, and decrease the surface free energy of rock surface from 72 to 1.6mN/m. The decrease in the gas displacement was approximately 30%. FT-IR, SEM and EDS were employed to determine the morphological change in the rock surface before and after gas-wetting alteration. Results indicate that when the fluorosurfactant molecules are joined to the nano-silica surface, and CF bond is recognized. The grape-like particles forming a multi-adsorption on the rock surface, which play an important role in super gas-wetting by decreasing surface free energy and increasing roughness on the rock surface. The data of EDS was consistent with the results of FT-IR and SEM. To further understand the influence of gas-wetting alteration on the flow and distribution of fluids in porous media, visualization flooding was conducted. The results show that the initial liquid saturation in the micromodel decreased sharply from 33.23% to 20.77% after the gas-wetting treatment, and the contact angle of isolated brine droplet on the treated pore-wall was approximately 125°, which also verifies that pore wettability can be altered to gas-wetting. The analytical data of the oil displacement experiment demonstrates that the substantial decrease in oil saturation may contributes to enhancing oil recovery. Furthermore, the mobility of oil trapped in micro channels can also be enhanced significantly after gas-wetting alteration due to the presence of methane.

Study on relative permeability characteristics affected by displacement pressure gradient: Experimental study and numerical simulation

The relative permeability is a key parameter for describing multiphase flow in porous media. In this paper, a series of experiments were conducted to study the impact of displacement pressure gradient (DPG) to relative permeability curves using five cores from Shengli Oilfield. Then, an empirical model was proposed to consider the impact of DPG. Finally, the numerical simulation model was established by introducing empirical correction formula into the traditional black oil model, and the effect of DPG on reservoir performance was analyzed. Result shows that with the increase of the DPG (in a range of 0.125–0.498MPa/m), the residual oil saturation decreases, the cross point of water and oil relative permeability curves moves to the right, and the relative permeability for water phase increases under the same water saturation. In the type III relative permeability curve, with the decrease of DPG, the water relative permeability decrease and the oil relative permeability keeps the same. With considering correction of relative permeability will improve the recovery factor and simulation accuracy.

Spontaneous countercurrent imbibition and forced displacement characteristics of low-permeability, siliceous shale rocks

Enhanced oil production from naturally-fractured low-permeability reservoirs is challenging. Spontaneous countercurrent imbibition in such reservoirs is an important oil recovery mechanism and has been widely studied in the oil and gas industry. Nevertheless, complicated rock properties such as low permeability, wettability, and other factors controlling flow mechanisms make it difficult to understand the flow characteristics and to generalize expected recovery. Spontaneous countercurrent imbibition and forced displacement tests were completed using siliceous shale core plugs that have low permeability, relatively high porosity, and intermediate to oil-wet surfaces. Four brine formulations were examined: carbonated synthetic brine, acidic (pH of 3), neutral, and alkaline (pH of 12). The siliceous shale core used in this study is an intermediate to oil-wet rock as gauged from the oil recovery by spontaneous imbibition in the neutral pH brine. With pH-controlled synthetic brine, the final oil recovery increases; especially using high pH brine. This suggests that the wettability shifts to a condition of greater water-wetness and the residual oil saturation decreases by exposing the system to a high pH brine. In the simulation study, it is inferred that the oil recovery characteristics change by changing the capillary pressure characteristics and the interfacial tension.

Effect of Elasticity on Displacement Efficiency: High-Concentration-Polymer Flooding

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 115315, "The Effect of Elasticity on Displacement Efficiency in the Laboratory and Results of High- Concentration-Polymer Flooding in the Field," by Haifeng Jiang and Wenxiang Wu, SPE, Daqing Petroleum Institute, and Demin Wang, SPE, Yeming Zeng, Shiguang Zhao, and Jun Nie, Daqing Oilfield Company, prepared for the 2008 SPE Annual Technical Conference and Exhibition, Denver, 21-24 September. The paper has not been peer reviewed. New studies show that when the pressure gradient and interfacial tension (IFT) remain constant, viscoelastic-polymer flooding can achieve higher displacement efficiency (DE). Laboratory flooding experiments on heterogeneous cores with high-concentration-polymer fluid showed that the higher the concentration and viscosity of the driving fluid, the higher the DE. Introduction The most commonly accepted mechanism for polymer flooding is that the DE is determined by the viscous pressure gradient and the retention force on residual oil. The former is proportional to the viscosity, μ, and velocity, v, of the driving fluid, and the latter is proportional to the IFT, σ. The ratio is defined as capillary number, Nc=μv/σ; therefore, the Nc determines DE. In polymer flooding, the IFT between the polymer fluid and crude oil is near that between water and crude oil, and, for certain reservoir systems, the overall pressure gradient can be increased only slightly; therefore, the Nc of polymer flooding is near that of waterflooding. According to the commonly accepted mechanism, the DE for polymer flooding should be the same as that for waterflooding. However, many test results in the laboratory and field show that the DE of polymer flooding is higher than that of waterflooding and that of viscous-fluid (e.g., glycerin) flooding. The theory that Nc determines the DE cannot explain the DE increase after polymer flooding. Because the Nc is the ratio of overall driving force to the retention force and because driving force is a viscous force, which reflects only the effect of the driving-fluid viscosity, the Nc theory is accurate in predicting the results of Newtonian-fluid flooding. For certain fluid/rock systems, the increase in viscosity cannot increase the DE when the overall pressure gradient remains constant. However, in viscoelastic-polymer flooding, the overall pressure gradient cannot explain the increase in DE, so the increase in DE is caused only by forces that do not change the overall pressure gradient (i.e., unrelated to viscosity), and these forces should be associated with the elasticity of the driving fluids. Microforce Visualization coreflood tests show that, when the oil saturation is high in viscous and viscoelastic-fluid flooding, oil blobs are pushed by the pressure gradient in pores, or become residual oil as the oil saturation decreases. However, in viscoelastic-fluid flooding, the residual-oil blob (oil droplet, film, or column) will have protruding portions that form mobile oil under driving forces. This phenomenon cannot be seen in viscous-fluid flooding, therefore, the driving forces in viscoelastic-fluid flooding are different from those in viscous-fluid flooding.

Experimental Study of Hot Water Injection into Low-Permeability Carbonate Rocks

Hot water drive involves the flow of only two heated phases. The major mechanisms on hot water injection are thermal expansion, viscosity reduction, wettability alteration, and oil/water IFT reduction. In this study, hot water injection experiments were carried out using unpreserved limestone and dolomite core samples obtained from the oil zones of heavy oil low-permeability reservoirs. These experiments were conducted at reservoir pressure but in various temperature ranges up to 500 °F using a wide variety of oils. The final oil recovery, residual oil saturation, irreducible water saturation, and pressure drop were compared in each experiment. The results of dynamic isothermal displacements were interpreted using numerical simulation method to obtain reliable relative permeabilities. Hence, the effects of temperature on oil/water relative permeabilities were obtained for low-permeability carbonate rocks. Results show that it is possible to recover a high percent of oil using high-pressure/high-temperature injection even from heavy oils in low-permeability carbonate reservoirs. In the heavy oil system, the oil production to hot water injection ratio is higher than in the medium and extra heavy oil, but the values are less than the reported values for conventional heavy oil reservoirs. Also, it was found that the relative permeabilities of oil/water depend on temperature and the residual oil saturation decreases and irreducible water saturation increases when the rock is heated.

New insights into the volume and pressure changes during the thermal cracking of oil to gas in reservoirs: Implications for the in-situ accumulation of gas cracked from oils

Previous pressure-volume calculations during oil cracking to gas, based on the conventional model that presupposes oil cracking to be completed by approximately 150C, underestimate the potential for gas accumulation in petroleum reservoirs. In this article, a compositional kinetic model of gas generation from oil cracking is suggested based on pyrolysis data using sealed gold tubes, and the pressure-volume changes are recalculated based on the new kinetic model under various geological conditions. The kinetic modeling of oil cracking confirms that crude oil begins cracking at about 160C for a heating rate of 2C/m.y., and that the oil-cracking process has two distinct stages with significant differences in gas composition. The first stage is characterized by dominant C2–5 wet gases, whereas the second is characterized by the recracking of C2–5 wet gases to methane and pyrobitumen, leading to a progressive increasing dryness of the gas. The pressure-volume-temperature simulations of oil cracking to gas show that initial oil saturation, temperature-pressure gradients, and openness of reservoirs are important geological factors that control gas accumulation in original petroleum reservoirs. For a reservoir that is geologically open and saturated with 100% oil, gas spills out of the trap at 196C. The gas loss at 240C is almost 50% of the total gas, far lower than the 75% based on the conventional model of oil destruction. With lower oil saturation, the gas loss decreases because the gas-water contact can shift downward, and the gas loss occurs mainly by solution. For effectively isolated reservoirs, oil cracking readily exceeds lithostatic pressure, leading to reservoir fracturing, which becomes more obvious when oil saturation decreases. The calculated fracturing temperatures for 100 and 50 vol.% oil saturations correspond to oil destructions of 95% and 86.4%, greatly exceeding the value of 1% as suggested by previous studies. A conceptual model of gas accumulation and loss in isolated and open geological conditions for a reservoir with 50% oil saturation is suggested. On the basis of this model, the Triassic carbonate gas pool in northeastern Sichuan Basin was discussed as a typical example for in-situ accumulation of gas cracked from reservoired oils. The present model infers that the reservoired oils were completely cracked into gas at 87.6 Ma, and that 75–85% of the gas has been preserved in the original reservoir rocks to form the in-situ gas pools with a huge amount of gas resources. We believe that gas accumulation from oil cracking in original petroleum reservoirs is much more prospective than previously thought, and that gas cracked from oil has great potential in other areas of the Sichuan Basin and the eastern Tarim Basin.

Temperature effects on the heavy oil/water relative permeabilities of carbonate rocks

In this study, unsteady-state relative permeability experiments were carried out using unpreserved limestone and dolomite core samples obtained from the oil zones of heavy oil carbonate reservoirs. Experiments were conducted at reservoir pressure and original fluid saturations for a temperature range of 100–500 °F. The oil/water relative permeabilities in various temperatures were determined using the JBN method and history matching of the experimental data using numerical simulations. The applicability and limitations of the JBN techniques are discussed. The results suggest that relative permeabilities of oil and water in heavy oil carbonate systems are functions of temperature. Specifically, the shape of oil relative permeability changes with increasing temperature which might be caused by wettability alterations due to elevated temperature. This, in fact, disagrees with some previous studies dealing with sandstone systems. It was found that the residual oil saturation decreases and irreducible water saturation increases with increasing temperature.

Residual Oil Saturation Inside the Steam Chamber During SAGD

Abstract The oil saturation inside the steam chamber during steamassisted gravity drainage (SAGD) has an important impact on economics and conservation. However, the SAGD residual oil saturation is difficult to determine and model because it involves long-term thermal effects and three-phase flow. SAGD has been widely studied and piloted, but improved understanding of longterm drainage effects represents a fundamental issue that requires improved understanding. In the first part of the paper, we represent a sensitivity test done on the shapes and the endpoints of the two-phase relative permeability curves. We find that the water relative permeability and oil relative permeability in the gas-oil system are the main factors that determine the magnitude and shape of the oil saturation curve as a function of time. Secondly, we demonstrate how to adjust the krog relative permeability curve to match a theoretically determined residual oil saturation, which is supported by laboratory data. We propose that, during SAGD, the flow of oil can be split into two regimes. In the first regime, close to the edge of the steam chamber, oil drains quickly in a short period of time. In the second regime, oil drains slowly within the steam chamber for a longer period of time, as it is produced by "film drainage." To capture these flow regimes, the oil relative permeability curve in the gas-oil system, krog, is split into two. At higher liquid saturations, the first flow regime is represented and, at lower liquid saturations, the second regime is modelled. Thirdly, the krog curve was adjusted so that the decrease in oil saturation with respect to time closely matched the theoretical curve while maintaining oil production rates expected for SAGD. Using this new curve at different pressures, we show that the residual oil saturation increases at lower SAGD operating pressures. Introduction In a steam-assisted gravity drainage (SAGD) process, bitumen drainage occurs mainly along the transition zone, which is the mobile liquid region at the boundary of the steam chamber. Bitumen drainage also continues to occur within the body of the steam chamber over a long period of time, such that the residual oil saturation gradually falls. In this paper, the term residual oil saturation refers to the average remaining oil saturation within the steam chamber where the steam chamber includes all grid blocks in a numerical model containing any amount of steam. It is difficult to obtain residual oil saturation data as a function of time in the field so, in this study, we relied on theoretical and laboratory data. We calibrated reservoir simulation results to the theoretical and laboratory data, and then used the simulator to investigate the effects of SAGD operating pressures on the residual oil saturation. Relative Permeability Formulation Multiphase flow in a porous medium can be described using Darcy's Law as follows:

Two-dimensional hydrodynamic lattice-gas simulations of binary immiscible and ternary amphiphilic fluid flow through porous media

The behavior of two-dimensional binary and ternary amphiphilic fluids under flow conditions is investigated using a hydrodynamic lattice-gas model. After the validation of the model in simple cases (Poiseuille flow, Darcy's law for single component fluids), attention is focused on the properties of binary immiscible fluids in porous media. An extension of Darcy's law which explicitly admits a viscous coupling between the fluids is verified, and evidence of capillary effects is described. The influence of a third component, namely, surfactant, is studied in the same context. Invasion simulations have also been performed. The effect of the applied force on the invasion process is reported. As the forcing level increases, the invasion process becomes faster and the residual oil saturation decreases. The introduction of surfactant in the invading phase during imbibition produces new phenomena, including emulsification and micellization. At very low fluid forcing levels, this leads to the production of a low-resistance gel, which then slows down the progress of the invading fluid. At long times (beyond the water percolation threshold), the concentration of remaining oil within the porous medium is lowered by the action of surfactant, thus enhancing oil recovery. On the other hand, the introduction of surfactant in the invading phase during drainage simulations slows down the invasion process-the invading fluid takes a more tortuous path to invade the porous medium-and reduces the oil recovery (the residual oil saturation increases).