Decrease In Residual Oil Saturation Research Articles

Time-dependent model for two-phase flow in ultra-high water-cut reservoirs: Time-varying permeability and relative permeability

For the ultra-high water-cut reservoirs, after long-term water injection exploitation, the physical properties of the reservoir change and the heterogeneity of the reservoir becomes increasingly severe, which further aggravates the spatial difference of the flow field. In this study, the displacement experiments were employed to investigate the variations in core permeability, porosity, and relative permeability after a large amount of water injection. A relative permeability endpoint model was proposed by utilizing the alternating conditional expectation (ACE) transformation to describe the variation in relative permeability based on the experimental data. Based on the time dependent models for permeability and relative permeability, the traditional oil-water two-phase model was improved and discretized using the mimetic finite difference method (MFD). The two cases were launched to confirm the validation of the proposed model. The impact of time-varying physical features on reservoir production performance was studied in a real water flooding reservoir. The experimental results indicate that the overall relative permeability curve shifts to the right as water injection increases. This shift corresponds to a transition towards a more hydrophilic wettability and a decrease in residual oil saturation. The endpoint model demonstrates excellent accuracy and can be applied to time-varying simulations of reservoir physics. The impact of variations in permeability and relative permeability on the reservoir production performance yields two distinct outcomes. The time-varying permeability of the reservoir results in intensified water channeling and poor development effects. On the other hand, the time-varying relative permeability enhances the oil phase seepage capacity, facilitating oil displacement. The comprehensive time-varying behavior is the result of the combined influence of these two parameters, which closely resemble the actual conditions observed in oil field exploitation. The time-varying simulation technique of reservoir physical properties proposed in this paper can continuously and stably characterize the dynamic changes of reservoir physical properties during water drive development. This approach ensures the reliability of the simulation results regarding residual oil distribution.

Re-Injection of Formation Water and Sea Water to Increase Oil Recovery from Sandstone Rocks: A Laboratory Experiment Under Room Conditions

Laboratory tests and field applications show that low-salinity water flooding could lead to significant reduction of residual oil saturation. There has been a growing interest with increasing number of low-salinity water flooding studies. However, there are few quantitative studies on the effect of using sea-water injections on oil recovery. As oil production continues, a drop-in reservoir pressure will occur due to the loss of reservoir fluids, and this drop-in pressure will lead to a decrease in oil production. The reservoir pressure is maintained by the water injection process. Where sea-water is injected into the aquifer area below the oil area to support the tank pressure. This study presents a laboratory investigation of the effect of salinity injection water on oil recovery, permeability, and relative permeability in the water flooding process. This study was conducted using several samples of sandstone saturated with oil by placing them in the reservoir conditions by placing them in a vacuum oven to ensure complete saturation of the samples with oil and then extracting the oil from them using liquid permeability where the samples are injected. With the formation water until reaching the recovery plateau and obtaining an average reading, the flow, permeability and pressure difference are measured, as well as the relative permeability and recovery factor, then the samples are injected again with sea water and the new results are recorded through seawater injection. The results of this study showed an increase in oil recovery with decrease in residual oil saturation and increase in the recovery factor.

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.

Numerical Modeling on the Influence of Effective Porosity, Microbial Kinetics, and Operational Parameters on Enhanced Oil Recovery by Microbial Flooding Within a Sandstone Formation

Summary During the implementation of a microbial-enhanced-oil-recovery (EOR) (MEOR) technique in a sandstone formation, various reservoir physicochemical, microbial kinetic, and operational parameters play major roles in governing the efficiency of crude-oil recovery from a hydrocarbon reservoir. The present study numerically investigates the sensitivity of sandstone formation effective porosity; different injected strains of the species Bacillus under optimal metabolic conditions and possessing distinct values of maximum microbial-specific-growth rate, Monod saturation constant, and yield coefficient; and crucial operational parameters on biomass and biosurfactant production and their effects on microscopic oil-displacement efficiency within the sandstone reservoir, along with prompting modifications in rock physicochemical properties. A black-oil biochemical multispecies reactive transport model in porous sandstone media is developed by coupling the kinetic model with the corresponding transport model involving microbial sorption. The governing equations involve coupled transport of nutrients and microbes by dispersion and convection, growth and decay rates of microbes, chemotaxis, nutrient consumption, and deposition of microbes and nutrients on rock-grain surfaces caused by reversible/irreversible sorption. Coupled empirical equations are used to estimate biosurfactant production, oil/water-interfacial-tension (IFT) reduction, change in the viscosity of injection fluid, and their effects on oil relative permeability and mobility, and thus a decrease in residual oil saturation within the reservoir. The finite-difference-discretization technique is adopted to solve the governing equations. Results of the present model are found to be numerically stable and match very well, when verified, with the previously published analytical, numerical, and experimental results. The model results suggest that at very low reservoir porosity (approximately 10%), an early breakthrough of nutrients, microbes, and biosurfactant leave insignificant concentrations in their respective fronts, which are insufficient for the recovery of the trapped oil. Also, increase in porosity to approximately 30% and beyond causes loss of nutrients, microbes, and biosurfactant because they undergo higher dispersion during their transport within the reservoir. Thus, sandstone formations possessing an intermediate effective porosity value of approximately 20% significantly enhance the efficiency of the overall MEOR process. Further, it is observed that the nature of microbes and nutrients used for MEOR application affect biosurfactant production, and in turn oil recovery, to a large extent. Those microbial species with far lower Monod-saturation-constant values have high affinity toward their substrates. This phenomenon dramatically increases the rates of nutrient consumption and production of biomass and biosurfactant within a reservoir when suitable substrate compounds are used, irrespective of differences in the yield coefficients of the microbes. Further MEOR simulation studies within a sandstone core exhibited maximum oil displacement and recovery at a run time of 5 hours, injected-microbial concentration of 4.32×10–3 mg/cm3, and maximum specific growth rate of 0.35 hours–1. Bioplugging-induced formation damage negatively affecting the oil-recovery efficiency is also observed with an increase in the process run time. The screened microbe also exhibited the possibility of wettability alteration of sandstone-formation rock from mixed/oil-wet to water-wet. Thus, the present study provides an improved understanding of the combined effects of reservoir porosity, microbial kinetic, and key operational parameters on fundamental MEOR processes, which will better characterize and develop an effective strategy to determine the suitability of an MEOR technique in a typical sandstone reservoir. Moreover, the developed numerical model is easier to implement and produces faster results with relatively lower computational cost, which helps in making a quick decision before applying MEOR processes in the field.

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 Novel Method with Dilute Surfactant Flooding by Considering the Effect of Time and Temperature on Crude Oil Aging, Experimental Study on Heavy Oil of Bangestan

Wettability alteration has been a sophisticated issue for scientists and reservoir engineers since early 20th century; thus, many investigations have been carried out to determine wettability and enhance it to ideal conditions, which leads to improvement in oil recovery. Dilute surfactant flooding has been approved as one of the noteworthy methods in chemical flooding. Several petroleum reservoirs were recognized as suitable nominees for surfactant/water flooding when screening criteria were established. Surfactant flooding was applied to mobilize the trapped oil in reservoirs. The key mechanism to enhance oil recovery by surfactant flooding was defined as rock wettability alteration. Experimental investigations into the impact of aging and temperature on wettability alteration were performed. Subsequently, core flooding test of surfactant was performed to define the effect of thinned cationic surfactant slug with cyclic 7 days technique (Multi-slug injection) on displacement sweep efficiency in the carbonate core of Bangestan reservoir with its heavy oil reservoir. Moreover, contact angle and interfacial tension (IFT) measurements were made to gain the supplementary information for a surfactant/waterflooding. The best concentration of C19TAB was determined by measuring interfacial tension values of the crude oil in contact with surfactant solutions prepared in synthetic brackish water. Results displayed a decrease in residual oil saturation by changing the contact angle and IFT reduction between oil and water. Moreover, aging was known as a significant constraint to change the wettability index to make similar oil-wet condition. Besides, laboratory experiments verified that the influence of wettability alteration was higher than IFT reduction.

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.

An experimental study of improved oil recovery through fines-assisted waterflooding

Abstract Permeability decline during waterflooding by varying water composition, in particular with low salinity or high pH water, has been observed in numerous laboratory studies. This has been explained by the lifting, migration and subsequent plugging of pores by fine particles. Recently, mathematical models have been presented to investigate the concept of using this permeability decline for mobility control during a waterflood. Now, these models need to be tested against observations during a core flood test. This paper presents a systematic laboratory study to investigate the underlying physics mechanisms for improved oil recovery as a consequence of injecting low-salinity water. Three sister plugs of Berea sandstone were used in the experiments. The first plug was subjected to single-phase waterflood for permeability measurements with varying salinities from 4 (high-salinity) to 0 (low-salinity) g/L NaCl. Core permeability decreased from 495 to 60 md, confirming the effect of changing water composition on permeability. The second plug saturated with high-salinity water was subjected first to primary oil flood (using Soltrol) to the connate water saturation and then to a benchmark waterflood using the same water. The oil recovery was noted and the core was restored to the connate water by a secondary oil flood. Finally, low-salinity waterflood was carried out and oil recovery was recorded. Experimental observations were interpreted using a numerical model. In order to check the reproducibility of the observations, the same experimental procedure was applied on the third plug. Results confirmed the reproducibility of the observations. Significant decrease in water relative permeability by approximately 50% and some decrease in residual oil saturation by about 5% were observed during the low-salinity waterflood in comparison with the high-salinity waterflood. Treatment of the low-salinity coreflood data by a numerical model reveals the decrease in water relative permeability with increasing water saturation at high water saturations. This observation is explained by the expansion of rock surface exposed to low-salinity water during the increase of water saturation. The laboratory data matched by the numerical model shows a high surface exponent value (nA=30), which is explained by a sharp surface area rise at high water saturations. The abnormal behavior of water relative permeability in response to low-salinity waterflood has resulted from matching water permeability increase at low water saturations and decrease at high saturations.

Effect of Temperature on Athabasca Type Heavy Oil – Water Relative Permeability Curves in Glass Bead Packs

There have been a number of somehow contradictory reports in the literature on the effect of temperature on oil and water relative permeabilities. Although some authors have reported the dependence of relative permeability curves on temperature, others have attributed these dependencies to artifacts inherent in unsteady-state method of relative permeability measurement. In order to further investigate the impact of temperature changes on the relative permeability data, we have conducted laboratory core flooding experiments on heavy oil systems. The porous media used was glass bead packs, and the Athabasca type bitumen with varying viscosities was displaced by hot water. The history matching technique was conducted on production and pressure differential data to get the relative permeability curves. Results indicated that generally the increase in initial water saturation and the decrease in residual oil saturation are expected by increasing temperature. However, viscous instabilities can rule out the above mentioned trends. No temperature dependency of either oil or water relative permeability can be justified in our tests. The changes in relative permeabilities by temperature are probably related to experimental artifacts, viscous fingering and changes in oil to water viscosity ratio and not fundamental flow properties.

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.

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.

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.

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).

96/01303 Preparation of coke for blast furnace

Permeability decline during waterflooding by varying water composition, in particular with low salinity or high pH water, has been observed in numerous laboratory studies. This has been explained by the lifting, migration and subsequent plugging of pores by fine particles. Recently, mathematical models have been presented to investigate the concept of using this permeability decline for mobility control during a waterflood. Now, these models need to be tested against observations during a core flood test.This paper presents a systematic laboratory study to investigate the underlying physics mechanisms for improved oil recovery as a consequence of injecting low-salinity water. Three sister plugs of Berea sandstone were used in the experiments. The first plug was subjected to single-phase waterflood for permeability measurements with varying salinities from 4 (high-salinity) to 0 (low-salinity) g/L NaCl. Core permeability decreased from 495 to 60 md, confirming the effect of changing water composition on permeability. The second plug saturated with high-salinity water was subjected first to primary oil flood (using Soltrol) to the connate water saturation and then to a benchmark waterflood using the same water. The oil recovery was noted and the core was restored to the connate water by a secondary oil flood. Finally, low-salinity waterflood was carried out and oil recovery was recorded. Experimental observations were interpreted using a numerical model. In order to check the reproducibility of the observations, the same experimental procedure was applied on the third plug. Results confirmed the reproducibility of the observations.Significant decrease in water relative permeability by approximately 50% and some decrease in residual oil saturation by about 5% were observed during the low-salinity waterflood in comparison with the high-salinity waterflood. Treatment of the low-salinity coreflood data by a numerical model reveals the decrease in water relative permeability with increasing water saturation at high water saturations. This observation is explained by the expansion of rock surface exposed to low-salinity water during the increase of water saturation. The laboratory data matched by the numerical model shows a high surface exponent value (nA=30), which is explained by a sharp surface area rise at high water saturations. The abnormal behavior of water relative permeability in response to low-salinity waterflood has resulted from matching water permeability increase at low water saturations and decrease at high saturations.

Effect of Temperature on Three-phase Water-oil-gas Relative Permeabilities of Unconsolidated Sand

Abstract The objective of this paper is to evaluate experimentally the effect of temperature on the three-phase brine-oil-gas relative permeabilities of an unconsolidated sand system. Two and threephase relative penneabilities have been measured at 75 °C and 125 °C. The experiments were performed under steady-state conditions. These measurements were conducted in Ottawa sand using a clean mineral oil 1% brine and nitrogen gas. The measured relative permeabilities showed no significant temperature effect. The three-phase brine relative permeability was found to be a function of brine saturation alone. The threephas gas relative permeability was always lower than the threephase values. This is consistent with some of the previously published results. The oil relative permeability was found to vary with the saturations or the other fluids. Oil isoperms were concave towards the oil apex. Finally, oil relative permeabilities were compared with predictions obtained using modifications of Stone's Methods I and II. The prediction of Stone I was good for both temperatures. But Stone II predictions were consistently lower than the experimental values. Introduction Three-phase relative permeability plays an important role in the numerical stimulation of oil recovery processes. Thermal methods for heavy oil recovery, such as steam drive and in situ combustion involve the simultaneous flow of three immiscible fluids through the porous rock formation at elevated temperatures. Over the past 25 years, a number of studies have evaluated the temperature effects on two -phase relative permabilities in porous media. Edmondson (1) found that the oil /water relative permeability of Berca sandstone was temperature dependent. In his experiment involving water flooding at elevated temperatures ranging from 24 ° to 260 °C (75 ° to 500 °F, be slowed a charge in relative permeability ratio accompanied by a decrease in residual of saturation with temperature increase. Davidson(2) investigated the temperature dependence of the permeability ration by conducting isothermal displacements of No. 15 white oil from an unconsolidated sandpack by either nitrogen, steam, or distilled water; and displacement of water by nitrogen. Values of the water oil permeability ratio were obtained over the temperature rang e of 24 ° to 282 °C (75 ° to 540 ° F) . At low water when hard, the gas-oil permeability ratio calculated from a nitrogen while oil displacement indicated a define dependence on temperature over the range 24 ° to 260 ° C (75 ° to 500 °F) and over the entire gas saturation range. He also found a decrease in residual oil saturation range. He also found a decrease in residual oil saturation with temperature increase. Poston et al. presented waterflood data for unconsolidated sandpacks containing 80.99 and 600 up viscosity oil a temperatures from 21 ° to 149 °C (70 ° to 300 °F), and observed an increase in the individual relative permeability curves as appeared temperature was increased. Although the water-oil permeability ratio appeared temperature sensitive no definite trend was found for the change of relative permeability ratio with temperature. They also found an increase in irreducible water saturation and a decrease in residual oil saturation as temperature increased. They concluded that unconsolidated sands became more water-wet with an increase in temperature.

Physics of Oil Entrapment in Water-Wet Rock

Summary Displacement of oil from an initially oil-filled porous rock by water consists of advancement of menisci and rupture of oil connections. In displacements controlled by capillarity, which are typical of oil reservoir floods, these pore-level events are governed by the local pore geometry, pore topology, and fluid properties, but the pressure field initiates these pore-level events and integrates them with the externally imposed Darcy flow. This paper reports the physics of the pore-level events and their integration on a computationally simple model of rock: a square network of pores. The novelty of the approach lies in keeping track of the evolution of the displacement front and in constructing an approximation of the entire pressure field that carries the information essential for predicting the evolution. The result gives insight into the state of the residual oil saturation and its dependence on pore geometry and the capillary number, Nca, of displacement. As the capillary number increases, the residual oil saturation decreases and the residual oil blobs tend to be smaller. As the pore size distribution becomes wider, the decrease of residual oil saturation with capillary number becomes smoother.

Effect Of Relative Permeability On The Numerical Simulation Of The Steam Stimulation Process

Abstract Thermal numerical simulators have been used to predict the performance of the steam stimulation processes. Our experience is that room temperature relative permeability curves measured on extracted core samples need to be adjusted to match field performance. This paper describes a study which was conducted to observe the effects of temperature on initial water saturations and residual oil saturations. A preserved core was mounted, stressed back to reservoir conditions and saturated with live reservoir oil, then waterfloods and oilfloods were run at reservoir and elevated temperatures. Two single-cycle numerical simulations were run. One utilized relative permeability curves derived from a room temperature waterflood on an extracted core which was saturated with mineral oil. The other simulation used the relative permeability curves from the preserved core, which was run with overburden pressure, and live crude oil. Both sets of simulations used temperature functional relationships for the residual oil saturationsand connate water saturations. The simulation which used the preserved core relative permeabilities resulted in matching the field water production much closer than the simulation using extracted core relative permeabilities. Introduction Relative permeabilities play an important role in the results of a numerical simulation using a thermal simulator. In thermal processes, the reservoir matrix and fluids undergo temperature changes. These temperature changes reduce the viscosity of the oil, cause rock fluid interactions to occur, and increase stresses within the rock matrix. A number of investigators have found that increases in temperature result in decreases in permeability; Afinogenou (1969). Weinbrandt (1972), and Okoh (l980). Other investigators have found that permeability either increases or remains constant. Gobran (1981) discusses the finding of these investigators. Somerton (1981) has estimated that porosity may decrease as much as 3 to 5 per cent as a result of increasing the temperature by 150 ºC. Edmondson (1965) found that the residual oil saturation decreases with increases in temperature. Poston (1970) and innokrot (1971) found that as the temperature increased the irreducible water saturation increased. Odeh (l965), Combarnous (1968), Wilson (1956) and Lo (1973) have postulated that the decrease in viscosity ratio is responsible for the decrease in residual oil saturation. Poston (1970) suggested the decrease in residual oil saturation was due to a change in wettability. Poston (1970) found that for unconsolidated sand both the relative permeability to oil and to water increased as the temperature increased. Weinbrandt (1972) used consolidated Boise sandstone and reported that the relative permeability to oil increased with temperature. The relative permeability to water decreased at low water saturations but increased at flood-out. The study of Lo (1973) using consolidated Berea sandstone and porous teflon cores found that relative permeability to oil and water increased with temperature. Dietrich (1981) developed a set of empirically derived relative permeability curves to match the performance of a cyclic steam stimulation process in a heavy oil reservoir. To simulate this process both imbibition and drainage relative permeabilities relationships were required. The empirically determined relative permeability curves were very different from those generally reported in the literature for unconsolidated sand.

A Study of the Vaporization of Crude Oil by Carbon Dioxide Repressuring

Abstract The object of this study was to determine if crude oil could be produced successfully by a process of crude oil vaporization using carbon dioxide repressuring. This process appears to have application to highly fractured formations where the major oil content of the reservoir is contained in the non-fractured porosity with little associated permeability. Crude oil was introduced into the windowed cell and carbon dioxide was charged to the cell at the desired pressure. A vapor space was formed above the oil, and the crude oil-carbon dioxide mixture was allowed to come to equilibrium. The vapor phase was removed and the vaporized oil collected as condensate. Samples of all produced and unproduced fluids were analyzed. Tests were also performed to evaluate the amount of vaporized oil that can be produced by rocking from a high to a lower pressure. The carbon dioxide repressuring process was applied to a sand-filled cell to investigate the performance in a porous medium. A test was performed to evaluate how the condensate recovery changes as the size of the gas cap in contact with the oil changes. Introduction This study has been directed toward a relatively new process of vaporization of crude oil designed to increase ultimate production of hydrocarbons through the application of carbon dioxide to an oil reservoir. Suggested advantages of carbon dioxide repressuring of a petroleum reservoir are: - reduction in viscosity of liquid hydrocarbons due to the solubility of carbon dioxide in crude oil, - swelling of the reservoir oil into a larger liquid-oil volume with a resulting increase in production and decrease in residual oil saturation due to an increase in the relative permeability to oil, - displacement of more stock-tank oil from the reservoir since the residual liquid is a swelled crude oil, and - gasification of some of the hydrocarbons into a carbon dioxide-hydrocarbon vapor mixture. Balanced against these advantages are several detrimental factors which must be evaluated; i.e., high compression costs and corrosion of well equipment and flow lines. Some of the more outstanding contributions to the study of carbon dioxide injection have been reviewed in order to furnish a basis for a continuation of research pertaining to this method. The literature reviewed has been limited to that dealing with carbon dioxide repressuring processes or with carbon dioxide-crude oil-natural gas phase behavior. Articles relating to carbonated water injection and literature published on the use of low pressure carbon dioxide gas injection in water flooding have not been included in this study. In 1941 Pirson suggested the high pressure injection of carbon dioxide into a partially depleted reservoir for the purpose of causing the reservoir oil to vaporize and thus produce the oil as a vapor along with the carbon dioxide gas. By reducing the pressure on this produced mixture of hydrocarbons and carbon dioxide at the surface, it was proposed to separate the hydrocarbons from the carrier gas. He theorized that essentially all the oil in a reservoir could be produced by simply injecting enough carbon dioxide to vaporize the residual oil. This present investigation deals with the vaporization of a crude oil by carbon dioxide, the molecular weight and gravity of the vaporized oil product and the characteristics of the residual oil after several repressuring cycles with carbon dioxide. An attempt is made to evaluate the merits of a vaporization process for the crude oil rather than a flow process where the oil recovery is determined by relative permeability considerations. Such a vaporize of crude oil by carbon dioxide repressuring appears to have possible use in a highly fractured formation where the major oil content of the reservoir is contained in the non-fractured porosity with little permeability. The carbon dioxide flows into the fractures, contacts the crude oil in the matrix and vaporizes part of the crude oil; this vaporized oil is produced and recovered and the carbon dioxide is reinjected again. The specific problem of this study is to attempt to answer this question; Can crude oil be produced successfully (technically, but without economic considerations) from a petroleum reservoir by a process of vaporization of the crude oil by carbon dioxide repressuring?