Imbibition Oil Recovery from Fractured, Water-Drive Reservoir

1962 ◽  
Vol 2 (02) ◽  
pp. 177-184 ◽  
Author(s):  
C.C. Mattax ◽  
J.R. Kyte
Keyword(s):  
Experimental Data ◽  
Oil Recovery ◽  
Reservoir Rock ◽  
Numerical Techniques ◽  
Large Reservoir ◽  
Small Reservoir ◽  
Matrix Block ◽  
Recovery Behavior ◽  
Matrix Blocks ◽  
Synthetic Models

Abstract Previous workers have developed differential equations to describe oil displacement by water imbibition, but have not explicitly defined the relationship between recovery behavior for a single reservoir matrix block and its size. In the present work, imbibition theory is extended to show that the time required to recover a given fraction of the oil from a matrix block is proportional to the square of the distance between fractures. Using this relationship, recovery behavior for a large reservoir matrix block is predicted from an imbibition test on a small reservoir core sample. The prediction is then extended to analyze recovery behavior for fractured - matrix, water - drive reservoirs in which imbibition is the dominant oil-producing mechanism. Experimental data are presented to support the basic imbibition theory relating matrix block size, fluid viscosity level and permeability to recovery behavior. Introduction Imbibition has long been recognized as an important factor in recovering oil from water - wet, fractured-matrix reservoirs subjected to water flood or water drive. Recently, two approaches have been published which might be used to predict imbibition oil-recovery behavior for reservoir - sized matrix blocks. Graham and Richardson used a synthetic model to scale a single element of a fractured-matrix reservoir. Blair, on the other hand, used numerical techniques to solve the differential equations describing imbibition in linear and radial systems. This latter method requires auxiliary experimental data in the form of capillary pressure and relative permeability functions. These two approaches, i.e., synthetic models and numerical techniques, have been used to study a variety of reservoir fluid-flow problems. One purpose of this work is to present, with experimental verification, a third method for predicting imbibition oil recovery for large reservoir matrix blocks. This method uses scaled imbibition tests on small reservoir core samples to predict field performance. The imbibition tests are easier to perform than the capillary pressure and relative permeability tests required to apply the numerical method. Furthermore, when suitably preserved reservoir-rock samples are used, the properties of the laboratory system are the same as those of the field. This offers an important advantage over the use of synthetic models because there is usually some question as to how accurately reservoir-rock properties can be duplicated in such models. Based on the recovery behavior for a unit matrix block, an analysis is presented to predict oil recovery for a fractured, water-drive reservoir made up of many such unit blocks. In the analysis, it is assumed that the flow resistance and the volume of the reservoir fracture system are negligible compared with that of the porous matrix. These assumptions are generally consistent with observed characteristics of many fractured-matrix reservoirs, and have been employed in previous studies. It is further assumed that the effect of gravity on flow in the matrix blocks is negligible. On first thought, the latter assumption might appear to seriously limit application of the method. However, in a fractured reservoir, the effect of gravity on flow in a matrix block will be restricted by the height of the block. Furthermore, matrix permeabilities are often very low (10 md or less) in such reservoirs. This means that capillary or imbibition forces will be large, thus tending to minimize the relative importance of gravity. For these reasons, imbibition should be the dominant oil-recovery mechanism in many fractured-matrix, water-drive reservoirs. The predictive method presented in this report is applicable to such reservoirs. SPEJ P. 177^

A Centrifuge Method To Predict Matrix-Block Recovery in Fractured Reservoirs

1970 ◽  
Vol 10 (02) ◽  
pp. 164-170 ◽  
Author(s):  
J.R. Kyte
Keyword(s):  
Oil Recovery ◽  
Recovery Process ◽  
Reservoir Rock ◽  
Gas Oil ◽  
Gravity Segregation ◽  
Centrifuge Method ◽  
Core Samples ◽  
Centrifuge Tests ◽  
Matrix Block ◽  
Matrix Blocks

Abstract Previous laboratory investigations to predict recovery from matrix blocks in a fractured reservoir have been primarily concerned with the imbibition oil recovery process. Gravity segregation can sometimes be more important than imbibition as a mechanism for oil recovery from matrix blocks. This paper describes a new method to predict oil recovery behavior for matrix blocks in a fractured-matrix reservoir. Centrifuge tests are performed with preserved reservoir core samples to scale the effects of both gravity and capillarity. The tests are easy to perform. Yet, The results should be more reliable than results obtained by other available methods for predicting matrix-block recoveries. Centrifuge tests were performed on different-sized reservoir rock samples to confirm the scaling theory. These tests were performed to simulate a water-oil displacement in a weakly water-wet reservoir. The method is equally applicable to other reservoir wettabilities and gas-oil displacements. In the weakly water-wet system, oil recovered by imbibition was found to be almost negligible as compared with the amount of oil recovered by gravity segregation. Introduction In many fractured-matrix reservoirs, most of the oil is contained in matrix blocks that are surrounded by a high-permeability fracture system. The flowing pressure gradient in the fractures is small, and pressure gradient in the fractures is small, and local capillary and gravity forces will dominate the recovery process for each matrix block. The unit matrix-block behavior then becomes an important factor in predicting reservoir oil recovery and assessing secondary or tertiary recovery prospects. Other investigators have used synthetic models and reservoir core samples to study the imbibition oil recovery process in fractured-matrix reservoirs. The methods they used to predict matrix-block recoveries are applicable when the reservoir rock is strongly wet by water and imbibition is the dominant mechanism for oil recovery. Wettability studies show that some reservoir rocks are not strongly wet by water in the presence of crude oil so that imbibition oil recovery will be low. Under these circumstances, gravity segregation can be an important mechanism for oil recovery, and its influence should be included in predicting matrix-block recovery. Marx has previously used scaling principles to show that the gas-oil gravity drainage characteristics of long, linear columns can be predicted from centrifuge tests on reconstituted core samples. In the current work, application of the scaling theory is extended to include three-dimensional systems and water-oil displacements. In addition, procedures are suggested to either duplicate or scale reservoir wettability and interfacial tension. The objectives of the present work are to present a centrifuge method that can be used to predict the effects of both gravity and capillarity on matrix-block oil recovery and to demonstrate the importance of gravity in recovering oil from matrix blocks in fractured reservoirs. In this paper, discussion of the centrifuge method will be limited, for the most part, to water-oil displacements. Application of the method to gas-oil displacements is discussed briefly near the end of the paper. PROCEDURE FOR PREDICTING PROCEDURE FOR PREDICTING MATRIX-BLOCK RECOVERY The laboratory procedure developed for predicting matric-block recovery consists of the predicting matric-block recovery consists of the following.Select a preserved core believed to have the same wettability, porosity and permeability as the prototype reservoir matrix block. prototype reservoir matrix block. A preserved core is defined as one cut and stored under conditions designed to preserve the original reservoir wettability.Cut a sample (or model) from the core so that it will simulate the reservoir matrix-block geometry in the centrifuge tests. SPEJ P. 164

Scaling of Countercurrent Imbibition in 2D Matrix Blocks With Different Boundary Conditions

SPE Journal ◽  
2019 ◽  
Vol 24 (03) ◽  
pp. 1179-1191 ◽  
Author(s):  
Qingbang Meng ◽  
Jianchao Cai ◽  
Jing Wang
Keyword(s):  
Experimental Data ◽  
Boundary Conditions ◽  
Oil Recovery ◽  
Characteristic Length ◽  
Fractured Reservoirs ◽  
Spontaneous Imbibition ◽  
Constant Parameter ◽  
Different Boundary Conditions ◽  
Recovery Curves ◽  
Matrix Blocks

Summary Scaling of imbibition data is of essential importance in predicting oil recovery from fractured reservoirs. In this work, oil recovery by countercurrent spontaneous imbibition from 2D matrix blocks with different boundary conditions was studied using numerical calculations. The numerical results show that the shape of imbibition-recovery curves changes with different boundary conditions. Therefore, the imbibition curves could not be closely correlated with a constant parameter. A modified characteristic length was proposed by a combination of Ma et al. (1997) and theoretical characteristic length. The modified characteristic length is a function of imbibition time, and the shape of imbibition curves could be changed using the modified characteristic length. The overall imbibition curves were closely correlated using the modified characteristic length. Finally, the modified characteristic length was verified by experimental data for imbibition with different boundary conditions.

Toward Field-Scale Wettability Modification—The Limitations of Diffusive Transport

2008 ◽  
Vol 11 (03) ◽  
pp. 633-640 ◽  
Author(s):  
Martin Stoll ◽  
Jan Hofman ◽  
Dick J. Ligthelm ◽  
Marinus J. Faber ◽  
Paul van den Hoek
Keyword(s):  
Capillary Pressure ◽  
Oil Recovery ◽  
Carbonate Rock ◽  
Water Pressure ◽  
Spontaneous Imbibition ◽  
Capillary Imbibition ◽  
Matrix Block ◽  
Laboratory Results ◽  
Matrix Blocks ◽  
The Matrix

Summary Densely-fractured oil-wet carbonate fields pose a true challenge for oil recovery that traditional primary and secondary processes fail to meet. The difficulty arises from the combination of two unfavorable characteristics: First, the dense fracturing frustrates an efficient waterflood; second, because of the oil-wetness, the water pressure exceeds the oil pressure inside the matrix blocks, thus inhibiting spontaneous imbibition of water. In the past decade, using a new class of surfactants, enhanced oil recovery (EOR) researchers have studied the options to chemically revert the wettability of carbonate rock without drastically decreasing the oil-water interfacial tension. These chemicals, termed "wettability modifiers" (WMs), effectively reverse the sign of capillary pressure at the prevalent saturation. With the oil pressure exceeding the water pressure, the capillary pressure becomes the driving force for oil expulsion from the matrix and into the fracture system. Previous publications on chemical wettability modification focused on the performance of different chemical wettability modifiers for a chosen rock/oil/brine system. In some cases, they demonstrated an almost full oil recovery from core plugs. Little attention, however, has been given to the mechanism underlying the transport of the chemical into the matrix block and to the proper scaling of laboratory results to reservoir size. The present study aims to demonstrate that imbibition after wettability modification is diffusion-limited. To this end, the recovery profiles for spontaneous capillary imbibition, as well as for imbibition after wettability modification, are calculated. The results are then used to compare with the data of Amott cell imbibition experiments. It is confirmed that in both cases, the cumulative recovery is initially proportional to the square root of time. Imbibition after wettability modification, however, takes approximately 1,000 times longer than spontaneous capillary imbibition into a water-wet medium. The slow recovery observed in the case of imbibition after wettability modification is in excellent agreement with the assumption that, in the absence of significant spontaneous imbibition, the WM, to unfold its action, must first diffuse into the porous medium. In any diffusion process, the time scale is linked to the square of the length scale of the medium. Therefore, it would take up to 1,000 times longer (an equivalent of 200 years) before the same recovery is obtained from a meter-scale matrix block as is obtained from a centimeter-scale plug in a laboratory in 100 days. Consequently, unless a significantly faster transport mechanism for the wettability modifier is identified, or unless viscous forces or buoyancy enable forced imbibition, the chemical wettability modification of fractured oil-wet carbonate rock does not provide an economically interesting opportunity. Introduction Rock fractures provide comparatively highly permeable flow paths through oil reservoirs. In a densely fractured reservoir, the permeability contrast between the fracture network and the oil-bearing matrix can be significant. In that case, the viscous pressure differential across individual matrix blocks can be too small to release oil from the blocks under waterflood, thus leading to a poor recovery. Depending on the wetting state of the matrix and its initial water saturation, Swi, capillary action can cause imbibition of water up to a "spontaneous" equilibrium saturation, commonly denoted as Sspw. At this saturation, however, the capillary pressure inside the matrix block coincides with that in the fracture, and the recovery ceases. Experience has shown that carbonate fields often range from intermediate-wet to preferentially oil-wet (Treiber et al. 1972; Chilingar and Yen 1983), which is synonymous with Sspw being close or equal to Swi ; thus, they exhibit very limited recovery during primary and secondary production. Recently, a new EOR technique, designed specifically to tackle the challenges outlined previously, has been suggested by Austad and coworkers (Austad and Milter 1997; Standnes and Austad 2000a, b). In their pioneering work, these authors show that certain chemicals, when dissolved in the surrounding brine, can initiate water imbibition into oil-saturated core plugs and, hence, lead to the recovery of oil. One possible mechanism that explains these observations is the solubilization of adsorbed hydrocarbon components from the pore surface—as demonstrated by an atomic force microscopy study by Kumar et al. (2005), this exposes the intrinsically hydrophilic matrix. Another possibility is the formation of an additional chemical layer covering the adsorbed hydrophobic material. In either case, the pore surface becomes more hydrophilic, and the wettability of the matrix is thus modified. In a capillary rise experiment into parallel plates, Kumar et al. also observed different time scales for different types of wettability-modifying chemicals (2005). Using the cationic wettability modifier dodecyl trimethyl ammonium bromide (DTAB, also known as C12TAB), Standnes and Austad deduced that wettability modification was achieved through the comparatively slow process of partitioning the chemical into the oil phase, followed by desorption and solubilization of anionic hydrocarbon components (2000a, b). Shen et al. (2006) and Rao et al. (2006) measured the effect of surfactants on the relative water/oil permeabilities at different interfacial tensions. Wu et al. (2006) studied the properties and ranked the efficiency of chemical model compounds, based on their chemical structure, to modify the wettability and enhance recoveries. Several groups have taken initiative to model wettability modification in numerical simulators (Adibhatla et al. 2005; Delshad et al. 2006). So far, no significant attention has been given to time dependence and to the subsequent upscaling of the laboratory results to matrix block scale. This subject will be addressed in the present work. The structure of the article is as follows: In the Theory section, the basic results for countercurrent capillary imbibition will be briefly reviewed and compared to Fick's law of molecular diffusion. The oil recovery as a function of time for both capillary imbibition and imbibition after wettability modification will be predicted. The experimental approach to imbibition at different wetting situations will be described in the section Materials and Preparation. The recovery results will then be analyzed using the previously derived equations. Finally, tentative conclusions for the upscaling will be drawn.

A New Dynamic Wettability-Alteration Model for Oil-Wet Cores During Surfactant-Solution Imbibition

SPE Journal ◽  
2013 ◽  
Vol 18 (05) ◽  
pp. 818-828 ◽  
Author(s):  
M. Hosein Kalaei ◽  
Don W. Green ◽  
G. Paul Willhite
Keyword(s):  
Experimental Data ◽  
Oil Recovery ◽  
History Matching ◽  
Mechanistic Model ◽  
Surfactant Solution ◽  
Experimental Tests ◽  
Quantitative Agreement ◽  
Wettability Alteration ◽  
Porous Rock ◽  
Surfactant Solutions

Summary Wettability modification of solid rocks with surfactants is an important process and has the potential to recover oil from reservoirs. When wettability is altered by use of surfactant solutions, capillary pressure, relative permeabilities, and residual oil saturations change wherever the porous rock is contacted by the surfactant. In this study, a mechanistic model is described in which wettability alteration is simulated by a new empirical correlation of the contact angle with surfactant concentration developed from experimental data. This model was tested against results from experimental tests in which oil was displaced from oil-wet cores by imbibition of surfactant solutions. Quantitative agreement between the simulation results of oil displacement and experimental data from the literature was obtained. Simulation of the imbibition of surfactant solution in laboratory-scale cores with the new model demonstrated that wettability alteration is a dynamic process, which plays a significant role in history matching and prediction of oil recovery from oil-wet porous media. In these simulations, the gravity force was the primary cause of the surfactant-solution invasion of the core that changed the rock wettability toward a less oil-wet state.

Unit Mobility Ratio Displacement Calculations for Pattern Floods in Homogeneous Medium

1966 ◽  
Vol 6 (03) ◽  
pp. 217-227 ◽  
Author(s):  
Hubert J. Morel-Seytoux
Keyword(s):  
Oil Recovery ◽  
Numerical Solutions ◽  
Mobility Ratio ◽  
Finite Difference Approximation ◽  
Difference Approximation ◽  
Numerical Techniques ◽  
Sweep Efficiency ◽  
Closed Form Solutions ◽  
Regular Patterns ◽  
Quantities Of Interest

Abstract The influence of pattern geometry on assisted oil recovery for a particular displacement mechanism is the object of investigation in this paper. The displacement is assumed to be of unit mobility ratio and piston-like. Fluids are assumed incompressible and gravity and capillary effects are neglected. With these assumptions it is possible to calculate by analytical methods the quantities of interest to the reservoir engineer for a great variety of patterns. Specifically, this paper presentsvery briefly, the methods and mathematical derivations required to obtain the results of engineering concern, andtypical results in the form of graphs or formulae that can be used readily without prior study of the methods. Results of this work provide checks for solutions obtained from programmed numerical techniques. They also reveal the effect of pattern geometry and, even though the assumptions of piston-like displacement and of unit mobility ratio are restrictive, they can nevertheless be used for rather crude but quick, cheap estimates. These estimates can be refined to account for non-unit mobility ratio and two-phase flow by correlating analytical results in the case M=1 and the numerical results for non-Piston, non-unit mobility ratio displacements. In an earlier paper1 it was also shown that from the knowledge of closed form solutions for unit mobility ratio, quantities called "scale factors" could be readily calculated, increasing considerably the flexibility of the numerical techniques. Many new closed form solutions are given in this paper. INTRODUCTION BACKGROUND Pattern geometry is a major factor in making water-flood recovery predictions. For this reason many numerical schemes have been devised to predict oil recovery in either regular patterns or arbitrary configurations. The numerical solutions, based on the method of finite difference approximation, are subject to errors often difficult to evaluate. An estimate of the error is possible by comparison with exact solutions. To provide a variety of checks on numerical solutions, a thorough study of the unit mobility ratio displacement process was undertaken. To calculate quantities of interest to the reservoir engineer (oil recovery, sweep efficiency, etc.), it is necessary to first know the pressure distribution in the pattern. Then analytical procedures are used to calculate, in order of increasing difficulty: injectivity, breakthrough areal sweep efficiency, normalized oil recovery and water-oil ratio as a function of normalized PV injected. BACKGROUND Pattern geometry is a major factor in making water-flood recovery predictions. For this reason many numerical schemes have been devised to predict oil recovery in either regular patterns or arbitrary configurations. The numerical solutions, based on the method of finite difference approximation, are subject to errors often difficult to evaluate. An estimate of the error is possible by comparison with exact solutions. To provide a variety of checks on numerical solutions, a thorough study of the unit mobility ratio displacement process was undertaken. To calculate quantities of interest to the reservoir engineer (oil recovery, sweep efficiency, etc.), it is necessary to first know the pressure distribution in the pattern. Then analytical procedures are used to calculate, in order of increasing difficulty: injectivity, breakthrough areal sweep efficiency, normalized oil recovery and water-oil ratio as a function of normalized PV injected.

Investigation of Emulsion Flow in Steam-Assisted Gravity Drainage

SPE Journal ◽  
2013 ◽  
Vol 18 (03) ◽  
pp. 440-447 ◽  
Author(s):  
C.C.. C. Ezeuko ◽  
J.. Wang ◽  
I.D.. D. Gates
Keyword(s):  
Experimental Data ◽  
Numerical Simulation ◽  
Oil Recovery ◽  
Vital Role ◽  
Gravity Drainage ◽  
Steam Assisted Gravity Drainage ◽  
Emulsion Flow ◽  
Very High ◽  
Effective Representation

Summary We present a numerical simulation approach that allows incorporation of emulsion modeling into steam-assisted gravity-drainage (SAGD) simulations with commercial reservoir simulators by means of a two-stage pseudochemical reaction. Numerical simulation results show excellent agreement with experimental data for low-pressure SAGD, accounting for approximately 24% deficiency in simulated oil recovery, compared with experimental data. Incorporating viscosity alteration, multiphase effect, and enthalpy of emulsification appears sufficient for effective representation of in-situ emulsion physics during SAGD in very-high-permeability systems. We observed that multiphase effects appear to dominate the viscosity effect of emulsion flow under SAGD conditions of heavy-oil (bitumen) recovery. Results also show that in-situ emulsification may play a vital role within the reservoir during SAGD, increasing bitumen mobility and thereby decreasing cumulative steam/oil ratio (cSOR). Results from this work extend understanding of SAGD by examining its performance in the presence of in-situ emulsification and associated flow of emulsion with bitumen in porous media.

Enhanced Oil Recovery Application of Nanoparticles in Niger Delta Water-Wet Reservoir Rock

2021 ◽  
Author(s):  
Tinuola Udoh
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Niger Delta ◽  
Oil Production ◽  
Reservoir Rock ◽  
Core Flooding ◽  
Core Samples ◽  
Recovery Potential ◽  
Secondary Formation ◽  
Injection Modes

Abstract In this paper, the enhanced oil recovery potential of the application of nanoparticles in Niger Delta water-wet reservoir rock was investigated. Core flooding experiments were conducted on the sandstone core samples at 25 °C with the applications of nanoparticles in secondary and tertiary injection modes. The oil production during flooding was used to evaluate the enhanced oil recovery potential of the nanoparticles in the reservoir rock. The results of the study showed that the application of nanoparticles in tertiary mode after the secondary formation brine flooding increased oil production by 16.19% OIIP. Also, a comparison between the oil recoveries from secondary formation brine and nanoparticles flooding showed that higher oil recovery of 81% OIIP was made with secondary nanoparticles flooding against 57% OIIP made with formation brine flooding. Finally, better oil recovery of 7.67% OIIP was achieved with secondary application of nanoparticles relative to the tertiary application of formation brine and nanoparticles flooding. The results of this study are significant for the design of the application of nanoparticles in Niger Delta reservoirs.

Nanoparticles Aid Oil Recovery During Alternating Injection

2021 ◽  
Vol 73 (09) ◽  
pp. 62-63
Author(s):  
Chris Carpenter
Keyword(s):  
Oil Recovery ◽  
Sodium Dodecyl ◽  
Surfactant Solution ◽  
Volatile Oil ◽  
Technical Conference ◽  
Reservoir Rock ◽  
Low Salinity ◽  
Low Salinity Water ◽  
Custom Made ◽  
Salinity Water

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 201586, “Effect of Silica Nanoparticles on Oil Recovery During Alternating Injection With Low-Salinity Water and Surfactant Into Carbonate Reservoirs,” by Saheed Olawale Olayiwola, SPE, and Morteza Dejam, SPE, University of Wyoming, prepared for the 2020 SPE Annual Technical Conference and Exhibition, originally scheduled to be held in Denver, Colorado, 5–7 October. The paper has not been peer reviewed. Although the potential of nanoparticles (NPs) to improve oil recovery is promising, their effect during alternating injection is still uncertain. The main objective of the authors’ study is to investigate the best recovery mechanisms during alternating injection of NPs, low-salinity water (LSW), and surfactant and transform the results into field-scale technology. The outcome of these experiments revealed that tertiary injection of NPs results in additional oil recovery beyond the limits of LSW. Introduction A series of coreflooding experiments was conducted using several cores with an effective permeability of approximately 1 md to the brine at a temperature and pressure of 70°C and 3,000 psi. The study performs four different alternating injections of NPs with LSW and surfactant to determine optimal oil recovery. The wettability of the rock and fluid and the interfacial tension (IFT) of oil and water are measured to understand the mechanisms of interactions between the fluids and the reservoir rock. Materials A 12×12×12-in. block taken from an outcrop of Indiana limestone reservoir was purchased for this study. Four core plugs with a diameter of 1.5 in., used for the coreflooding experiments, were selected from this block. A synthetic 100,000-ppm (10 wt%) brine was prepared in the laboratory by dissolving sodium chloride (NaCl) and calcium chloride with a ratio of 4:1 in deionized water. The crude oil used in this study was a volatile oil (properties are described in Table 2 of the complete paper) obtained from the Permian Basin in Texas. Injected Fluids. A 10,000-ppm (1 wt%) LSW was prepared by diluting the synthetic brine 10 times. The surfactant solutions were prepared from an anionic sodium dodecyl sulfate (SDS) surfactant. A 1,000-ppm (0.1 wt%) surfactant solution used throughout the experiments was selected on the basis of the estimated critical micelle concentration of 600 to 2,240 ppm for SDS and nanofluid/NaCl. The concentration of silica NPs used in this study was 500 ppm (0.05 wt%). The nanofluids were pre-pared either as a simple solution or as a mixture with other chemicals to make a concentration of 500-ppm silica NPs. Coreflooding System. The established coreflooding system used for this experimental study was custom-made to determine the oil recovery and the relative permeabilities at steady-state and unsteady-state flows. However, the focus of this study is to investigate the effect of silica NPs on oil recovery. The schematic diagram of the coreflooding system is shown in Fig. 1.

scholarly journals Modelling Macrophage Infiltration into Avascular Tumours

2002 ◽  
Vol 4 (1) ◽  
pp. 21-38 ◽  
Author(s):  
C. E. Kelly ◽  
R. D. Leek ◽  
H. M. Byrne ◽  
S. M. Cox ◽  
A. L. Harris ◽  
...  
Keyword(s):  
Experimental Data ◽  
Mathematical Model ◽  
Spatial Structure ◽  
Random Motion ◽  
Numerical Results ◽  
Macrophage Infiltration ◽  
Numerical Techniques ◽  
Model Predictions ◽  
Independent Experimental Data

In this paper a mathematical model that describes macrophage infiltration into avascular tumours is presented. The qualitative accuracy of the model is assessed by comparing numerical results with independent experimental data that describe the infiltration of macrophages into two types of spheroids: chemoattractant-producing (hepa-1) and chemoattractant-deficient (or C4) spheroids. A combination of analytical and numerical techniques are used to show how the infiltration pattern depends on the motility mechanisms involved (i.e. random motion and chemotaxis) and to explain the observed differences in macrophage infiltration into the hepa-1 and C4 spheroids. Model predictions are generated to show how the spheroid's size and spatial structure and the ability of its constituent cells influence macrophage infiltration. For example, chemoattractant-producing spheroids are shown to recruit larger numbers of macrophages than chemoattractant-deficient spheroids of the same size and spatial structure. The biological implications of these results are also discussed briefly.

scholarly journals Laboratory Studies of Carboniferous Reservoirs of High-Viscosity Oil Fields Using Carbondioxide

2020 ◽  
Vol 20 (4) ◽  
pp. 369-385
Author(s):  
Stanislav A. Kalinin ◽  
◽  
Oleg A. Morozyuk ◽  
Keyword(s):  
Carbon Dioxide ◽  
Heat Carrier ◽  
Oil Recovery ◽  
High Mobility ◽  
High Viscosity ◽  
Laboratory Studies ◽  
Carbon Dioxide Injection ◽  
Recovery Method ◽  
Matrix Blocks ◽  
High Viscosity Oil

It is of current concern for the Permian-Carboniferous reservior of the Usinskoye field to develop low-permeable matrix blocks of carboniferous reservoirs, which contain major reserves of high-viscosity oil. To increase effectiveness of the currently used thermal oil recovery methods, the authors suggest using carbon dioxide as a reservoir stimulation agent. Due to a high mobility in its supercritical condition, СО2 is, theoretically, able to penetrate matrix blocks, dissolve in oil and, additionally, decrease its viscosity. Thus, СО2 applications together with a heat carrier could increase effectiveness of the high-viscosity oil recoveries and improve production parameters of the Permian-Carboniferous reservior of the Usinskoye field. During carbon dioxide injections, including combinations with various agents, some additional oil production is possible due to certain factors. Determination of the influencing factors and detection of the most critical ones is possible in laboratory tests. So, laboratory studies entail the key stage in justification of the technology effectiveness. The paper deals with describing the laboratory facilities and methodologies based on reviews of the best world practice and previous laboratory researches. These aim at evaluating effectiveness of thermal, gas and combined oil recovery enhancement methods. In particular, the authors explore experimental facilities and propose methodology to perform integrated researches of the combined heat carrier and carbon dioxide injection technology to justify the effective super-viscous oil recovery method.

Sign in / Sign up

Export Citation Format

Share Document