Computer-Assisted Tomography for the Observation of Oil Displacement in Porous Media

1984 ◽  
Vol 24 (01) ◽  
pp. 53-55 ◽  
Author(s):  
Simon Y. Wang ◽  
Seyda Ayral ◽  
Carl C. Gryte
Keyword(s):  
Cross Section ◽  
Oil Recovery ◽  
Computer Assisted ◽  
Berea Sandstone ◽  
Oil Saturation ◽  
X Ray ◽  
The Core ◽  
Oil Displacement ◽  
Cat Scan ◽  
Saturation Distribution

Abstract Computer-assisted tomography (CAT) is used to obtain cross-sectional images of Berea sandstone cores during oil displacement experiments. Local oil saturation averaged over an area of about 0.03 × 0.03 in. [0.8 × 0.8 mm] square is computed as a function of spatial position and time. A series of CAT scan images displaying the time evolution of the fluid distribution at one cross section are shown to illustrate the formation of viscous ringers. Introduction CAT 1–2 is a method that uses computerized mathematical algorithms to reconstruct tomographic image of an object. The image reconstruction is based on multiple X-ray measurements made around the object's periphery. This technique has been used in the present research to obtain oil saturation distribution information during immiscible oil displacement in Berea sandstone cores. The objective is to investigate various problems involved in oil recovery processes, including,heterogeneity of the porous structure,surface interactions between oil. the displacing fluid, and the reservoir rock formation, andthe viscosity ratio between the two fluids. The flow phenomenon is very complex. and previous experimental methods have offered insufficient information for the understanding of oil recovery processes. The CAT scan image acquisition is rapid: thus, it yields directly local oil saturations over a cross section as a function of spatial position and time. Dynamic fluid distribution profiles then can be used to analyze the effectiveness of various oil recovery strategies. Experiment An unmodified second-generation CAT scan apparatus (DeltaScan-50 CT scanner by Ohio-Nuclear) is used to obtain oil distribution histories during immiscible oil displacement experiments in oil-bearing Berea sandstone cores. In spite of the dense silica materials. CAT scan has been used successfully to observe fluid flow in sandstone cores. The porous-media models used in this laboratory are cylindrical Berea sandstone cores (5 cm in diameter and 25 cm in length). The permeability of the core is 300 aid, and the porosity is about 20%. The core initially was evacuated and filled completely with oil. A displacing fluid of 1 M KI solution was injected into the core at a rate of 10 mL/hr [10 cm3/h] (superficial velocity is approximately 24 in./D 160 cm/d]). This core was placed in the CAT scanner, and cross-sectional images were taken at different axial locations and different times during the displacement experiment. The computer unit computes local X-ray attenuation coefficients over the scanning, cross section for picture elements of 0.8 by 0.8 mm [0.03 × 0.03 in.] per square. The thickness of the element is approximately equal to the width of the X-ray beam, which is about 1 cm [0.4 in.]. These average X-ray attenuation coefficients result from linear combinations of the silica rock formation and the oil/KI solution mixtures that occupy the pore spaces. Therefore, the oil saturation distribution over a cross section can be computed from local X-ray attenuation data for each CAT scan image. Results and Discussion A typical CAT scan image showing the oil saturation distribution at a certain axial position is illustrated in Fig. 1. Darker regions indicate water-rich area where most of the oil has been displaced, and lighter regions indicate oil-rich area. From Fig. 1, the spatial distribution of oil and water can be observed. The ordered fluid saturation changes seem to indicate sonic periodicities coincident with the presence of bedding planes existing in Berea sandstone cores. If sequential scannings are taken at different axial positions at a given time, the structure of the water "fingers" can be reconstructed. Figs. 2A, 2B, and 2C plot the oil saturation distributions at 5 cm [2 in.] from the injection point after 3, 4.5, and 15 PV of the displacing fluid (1 M KI) have been injected into the sandstone core. The top of the diagram indicates 100% oil, and the bottom of the diagram indicates 100% water (1 M KI). These CAT scan images have dramatically represented the invasion of water into the oil region and the displacement of oil from a specific cross section as a function of time. Time derivatives of oil saturations also are computed from these image data, which yield rate of changes of local oil saturations SPEJ P. 53^

Coreflood Model Calibration for Alkali Surfactant Polymer Process from a High Salinity Reservoir to Design an ASP Pilot

2021 ◽  
Author(s):  
Marisely Urdaneta
Keyword(s):  
Numerical Simulation ◽  
Simulation Model ◽  
Oil Recovery ◽  
Water Saturation ◽  
Polymer Concentration ◽  
Chemical Flooding ◽  
Adsorption Parameters ◽  
Oil Saturation ◽  
The Core ◽  
Asp Flooding

Abstract This paper aims to address calibration of a coreflood Alkali Surfactant Polymer (ASP) formulation experiment through parametrization of fluid-fluid and rock-fluid interactions considering cation exchange capacity and by rock to guide an ASP pilot design. First of all, a series of chemical formulation experiments were studied in cores drilled from clastic reservoir so that displacement lab tests were run on linear and radial cores to determine the potential for oil recovery by ASP flooding and recommended the chemical formulation and flooding schemes, in terms of oil recovery. Therefore, to simulate the process, those tests performed with radial core injection were taken, because this type of test has a better representation of the fluid flow in reservoir, the fluids are injected by a perforation in the center of the core, moving in a radial direction the fluids inside the porous medium. Subsequently, displaced fluids are collected on the periphery of the core carrier and stored in graduated test tubes. The recommended test was carried out to the phase of numerical simulation and historical matching. Reservoir simulation is one of the most important tools available to predict behavior under chemical flooding conditions and to study sensitivities based on cost-effective process implementation. Then, a radial core simulation model was designed from formulation data with porosity of 42.6%, a pore volume (PV) of 344.45 ml, radius of 7.17 cm and weight of 1225.84 g. The initial oil saturation was 0.748 PV (257.58 ml), with a critical water saturation of 0.252 PV (86.78 ml). For the simulation model historical matching, adjustments were made until an acceptable comparison was obtained with laboratory test production data through parameterization of relative permeability curves, chemical adsorption parameters, polymer viscosity, among others; resulting in an accumulated effluents production mass 37% greater for alkali than obtained in the historical, regarding to surfactant the deviation was 8% considered acceptable and for the polymer the adjustment was very close. For the injector well bottom pressure, the viscosity ratio of the mixture was considered based on the polymer concentration and the effect of the shear rate on the viscosity of the polymer as well as the effect of salinity in the alkali case. Finally, a calibrated coreflood numerical simulation model was obtained for ASP flooding to design an ASP Pilot with a residual oil saturation of 0.09 PV (31 ml) meaning 64% more recovered oil compared to a waterflooding case.

Laboratory Tests on Heavy Oil Recovery by Steam Injection

1983 ◽  
Vol 23 (03) ◽  
pp. 417-426 ◽  
Author(s):  
Philip J. Closmann ◽  
Richard D. Seba
Keyword(s):  
Pore Size ◽  
Heat Loss ◽  
Oil Recovery ◽  
Heavy Oil ◽  
Steam Injection ◽  
Residual Oil ◽  
Oil Saturation ◽  
Residual Oil Saturation ◽  
The Core ◽  
Unconsolidated Sand

Abstract This paper presents results of laboratory experiments conducted to determine the effect of various parameters on residual oil saturation from steamdrives of heavy-oil reservoirs. These experiments indicated that remaining oil saturation, both at steam breakthrough and after passage of several PV of steam, is a function of oil/water viscosity ratio at saturated steam conditions. Introduction Considerable attention has been given to thermal techniques for stimulating production of underground hydrocarbons, particularly the more viscous oils production of underground hydrocarbons, particularly the more viscous oils and tars. Steam injection has been studied as one means of heating oil in place, reducing its viscosity, and thus making its displacement easier. place, reducing its viscosity, and thus making its displacement easier. A number of investigators have measured residual oil saturations remaining in the steam zone. Willman et al. also analyzed the steam displacement process to account for the oil recoveries observed. A number of methods have been developed to calculate the size of the steam zone and to predict oil recoveries by application of Buckley-Leverett theory, including the use of numerical simulation. The work described here was devoted to an experimental determination of oil recovery by steam injection in linear systems. The experiments were unscaled as far as fluid flow rates, gravity forces, and heat losses were concerned. Part of the study was to determine recoveries of naturally occurring very viscous tars in a suite of cores containing their original oil saturation. The cores numbered 95, 140, and 143 are a part of this group. Heterogeneities in these cores, however, led to the extension of the work to more uniform systems, such as sandpacks and Dalton sandstone cores. Our interest was in obtaining an overall view of important variables that affected recovery. In particular, because of the significant effect of steam distillation, most of the oils used in this study were chosen to avoid this factor. We also studied the effect of pore size on the residual oil saturation. As part of this work, we investigated the effect of the amount of water flushed through the system ahead of the steam front in several ways:the production rate was varied by a factor of four,the initial oil saturation was varied by a factor of two, andthe rate of heat loss was varied by removing the heat insulation from the flow system. Description of Apparatus and Experimental Technique Two types of systems were studied: unconsolidated sand and consolidated sandstone. The former type was provided by packing a section of pipe with 50–70 mesh Ottawa sand. Most runs on this type of system were in an 18-in. (45.72-cm) section of 1 1/2 -in. (3.8 1 -cm) diameter pipe, although runs on 6-in. (15.24-cm) and 5-ft (152.4-cm) lengths were also included. Consolidated cores 9 to 13 in. (22.86 to 33.02 cm) long and approximately 2 1/4 in. (5.72 cm) in diameter were sealed in a piece of metal pipe by means of an Epon/sand mixture. A photograph of two 9-in. (22.86-cm) consolidated natural cores (marked 95 and 143) from southwest Missouri, containing original oil, is shown as Fig. 1. In all steamdrive runs, the core was thermally insulated to reduce heat loss, unless the effect of heat loss was specifically being studied. Flow was usually horizontal except for the runs in which the effects of flushing water volume and of unconsolidated-sand pore size were examined. Micalex end pieces were used on the inlet end in initial experiments with consolidated cores to reduce heat leakage from the steam line to the metal jacket on the outside of the core. During most runs, however, the entire input assembly eventually became hot. SPEJ p. 417

Analysis of the Effect of Residual Oil on Particle Trapping During Produced-Water Reinjection Using X-Ray Tomography

SPE Journal ◽  
2010 ◽  
Vol 15 (04) ◽  
pp. 943-951 ◽  
Author(s):  
A.. Saraf ◽  
A.H. de Zwart ◽  
Peter K. Currie ◽  
Mohammad A.J. Ali
Keyword(s):  
Direct Observation ◽  
Particle Deposition ◽  
Produced Water ◽  
Water Injection ◽  
Residual Oil ◽  
Ct Scanner ◽  
Oil Saturation ◽  
Residual Oil Saturation ◽  
X Ray ◽  
The Core

Summary Recently, it has been shown that the presence of residual oil in a formation can have a considerable influence on the trapping mechanisms for particles present in reinjected produced water (Ali 2007; Ali et al. 2005, 2007, 2009). This article reports on a further set of extensive coreflow experiments that confirm and extend these results. The tests were conducted in a computerized-tomography (CT) scanner, allowing direct observation of the buildup of particle deposition along the core. These experiments are relevant to operational issues associated with produced-water reinjection (PWRI). In many cases, produced water is injected into formations containing oil, so reduced oil saturation is achieved rapidly in the area around the well. Even if the well is outside the oil zone, trapped oil droplets are always present in produced water, and a residual-oil zone will gradually build up around the well. Major differences are found between the deposition profiles for fully water-saturated cores and the cores having residual-oil saturation. In particular, particles penetrate deeper into the core with residual-oil saturation, and considerably more particles pass completely through the core without being trapped. The X-ray technique allows direct observation during the experiment of the deposition process inside the core, eliminating the complicating effect of any external filter cake. As a result, an analysis can be performed of the deposition parameters relevant inside the core using deep-bed-filtration theory, and the results of this analysis are presented. In particular, it is shown that the values of the filtration function determined from the CT-scan (X-ray) data are consistent with those obtained from analysis of the effluent concentration. Moreover, both methods of analysis find quite clearly that the filtration coefficient increases with decreasing flow rate. The results indicate that formation damage near a wellbore during water injection will be reduced by the presence of residual oil, and that particles will penetrate deeper into the formation. The result is also relevant to injection under fracturing conditions because particle deposition in the wall of the fracture (where residual oil may be present) is one of the mechanisms governing fracture growth.

scholarly journals Improving Oil Recovery of the Heterogeneous Low Permeability Reservoirs by Combination of Polymer Hydrolysis Polyacrylamide and Two Highly Biosurfactant-Producing Bacteria

2021 ◽  
Vol 14 (1) ◽  
pp. 423
Author(s):  
Shuwen Xue ◽  
Yanhong Zhao ◽  
Chunling Zhou ◽  
Guangming Zhang ◽  
Fulin Chen ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Low Permeability ◽  
Bacterial Fermentation ◽  
The Core ◽  
Oil Displacement ◽  
Polymer Hydrolysis ◽  
Enhance Oil Recovery ◽  
Low Permeability Reservoirs ◽  
Microbial Flooding ◽  
Poly Acrylamide

Polymer hydrolysis polyacrylamide and microbes have been used to enhance oil recovery in many oil reservoirs. However, the application of this two-method combination was less investigated, especially in low permeability reservoirs. In this work, two bacteria, a rhamnolipid-producing Pseudomonas aeruginosa 8D and a lipopeptide-producing Bacillus subtilis S4, were used together with hydrolysis poly-acrylamide in a low permeability heterogeneous core physical model. The results showed that when the two bacterial fermentation liquids were used at a ratio by volumeof 1:3 (v:v), the mixture showed the optimal physicochemical properties for oil-displacement. In addition, the mixture was stable under the conditions of various temperature (20–70 °C) and salinity (0–22%). When the polymer and bacteria were mixed together, it had no significant effects in the viscosity of polymer hydrolysis polyacrylamide and the viability of bacteria. The core oil-displacement test displayed that polymer hydrolysis polyacrylamide addition followed by the bacterial mixture injection could significantly enhance oil recovery. The recovery rate was increased by 15.01% and 10.03%, respectively, compared with the sole polymer hydrolysis polyacrylamide flooding and microbial flooding. Taken together, these results suggest that the strategy of polymer hydrolysis poly-acrylamide addition followed by microbial flooding is beneficial for improving oil recovery in heterogeneous low permeability reservoirs.

The Impact of Nanoparticles Adsorption and Transport on Wettability Alteration of Intermediate Wet Berea Sandstone

2015 ◽  
Author(s):  
Shidong Li ◽  
Ole Torsæter
Keyword(s):  
Pressure Drop ◽  
Oil Recovery ◽  
Fluid Pressure ◽  
Injection Pressure ◽  
Wettability Alteration ◽  
Colloidal Nanoparticles ◽  
Berea Sandstone ◽  
Nano Structure ◽  
The Core ◽  
The Impact

AbstractNanoparticles as part of nanotechnology have drawn the attention for its great potential of increasing oil recovery. From authors' previous studies (Li et al., 2013a), wettability alteration was proposed as one of the main Enhanced Oil Recovery (EOR) mechanisms for nanoparticles fluid, as adsorption of nanoparticles on pore walls leads to wettability alteration of reservoir. We conducted a series of wettability measurement experiments for aged intermediate-wet Berea sandstone, where the core plugs were treated by different concentration and type of nanoparticles fluid. Nanoparticles transport experiments also were performed for core plugs with injection of varying concentration and type of nanoparticles fluid. Pressure drop across the core plug during injection was recorded to evaluate nanoparticles adsorption and retention inside core, as well as desorption during brine postflush. Both hydrophilic silica nano-structure particles and hydrophilic silica colloidal nanoparticles were utilized in above two experiments.The results of wettability alteration experiments indicated that hydrophilic nanoparticles have ability of making intermediate-wet Berea sandstone to be more water wet, and basically the higher concentration the more water wet will be. And different type of nanoparticles has different effect on the wettability alteration process. For nanoparticles transport experiments, the results showed that the nanoparticles undergo both adsorption and desorption as well as retention during injection. Pressure drop curves showed that absorption and retention of nano-structure particles inside core was significant while colloidal nanoparticles did not adsorb much. Permeability impairment was observed during nano-structure particles fluid injection, but on the contrary colloidal nanoparticles dispersion injection made core more permeable.

Investigation of CO2 Diffusion in Oil-Saturated Porous Media by Using X-Ray Computer-Assisted Tomography

2013 ◽  
Vol 807-809 ◽  
pp. 2498-2502 ◽  
Author(s):  
Ling Yue Tang ◽  
Yu Liu ◽  
Yong Chen Song ◽  
Zi Jian Shen ◽  
Xin Huan Zhou
Keyword(s):  
Porous Media ◽  
Oil Recovery ◽  
Diffusion Coefficients ◽  
Critical Parameter ◽  
Petroleum Industry ◽  
Computer Assisted ◽  
Saturated Porous Media ◽  
X Ray ◽  
Computer Assisted Tomography ◽  
The Relationship

In petroleum industry injection of carbon dioxide has a lot of economical advantages for oil recovery. The diffusion coefficient of CO2 in oil-saturated porous media is a critical parameter. However, there is no universally applicable technique for measuring the diffusion coefficients of gas in oil-saturated porous media. The main objective of this work is to develop a possible experimental method for measuring CO2 diffusion coefficients in oil-saturated porous media by CT technique. At last the relationship between pressure and diffusivity at T= 29 °C is discussed.

Sulfonate Retention and Residual Oil Saturation

1983 ◽  
Vol 23 (02) ◽  
pp. 349-357 ◽  
Author(s):  
C. Travis Presley
Keyword(s):  
Oil Recovery ◽  
Core Material ◽  
Residual Oil ◽  
Oil Saturation ◽  
Residual Oil Saturation ◽  
The Core ◽  
Polymer Flood ◽  
Core Elements ◽  
The Individual ◽  
Individual Core

Abstract This paper describes an empirical relationship between sulfonate retention and final residual oil saturation achieved by a micellar/polymer oil-recovery process. Using this relationship and certain assumptions, one can derive expressions for predicting oil recovery performance in coreflood experiments. The equations contain two experimental constants:sulfonate retention anda factor related to the oil-recovery efficiency of the sulfonate slug in cores, specific to both the slug and core material. This same relationship applies to both linear and radial cores. The equations derived predict nonlinear scaling effects. These effects have been demonstrated in laboratory corefloods. Introduction Sulfonate retention, as defined in the literature, represents the loss of a critical component and consequently affects the efficiency of micellar/polymer oil-recovery processes. In this case, sulfonate retention is discussed in connection with laboratory corefloods. An operational definition of the retained sulfonate is that quantity of sulfonate remaining in the core, by whatever mechanism, after a core has been flushed with drive fluid to final oil saturation. The remainder of the originally injected sulfonate has presumably been propagated through the core. For the systems studied. a relationship has been found between residual oil saturation after a micellar/polymer flood and the net amount of sulfonate propagated through a given element of core. This relationship was established by determining residual oil saturation and sulfonate retention in successive sections of flooded cores taken along the direction of increasing travel of micellar slug. The measurements were obtained by a postflood extraction of these core sections and subsequent analysis of the extract. These data were analyzed by viewing a coreflood as a series of smaller sequential floods of the core elements where each successive element was treated with less sulfonate. Effect of Sulfonate Retention on Residual Oil Saturation Linear Cores Coreflood data were collected using Slug A and Henry crude oil in fired Berea sandstone cores that previously had been waterflooded to residual oil saturation. Slug composition is given in Appendix A. Each coreflood experiment was performed using four cylindrical cores connected in series to form one composite core. The individual core segments were each 2 in. × 1 ft long (5.2 cm × 30.5 cm), so that the composite core was 4 ft (1.2 m) long. Experimental details of the flooding method are discussed in Appendix B. After a micellar/polymer flood was completed, the composite core was separated and the individual core elements were analyzed for oil saturation and sulfonate retention. The analytical procedure is described in Appendix B and is patterned after the method described by Smith et al. By performing the experiments in this way, we obtain the average residual oil saturation over the individual segments of a flooded core. We have called these values "point oil saturation," (Sor)m, to distinguish them from the average oil saturation over the composite core, which we have called average oil saturation," S orj. Fig. 1 shows two interpretations of these tandem corefloods. Fig. 1a shows the quantities that are measured experimentally. The amount of sulfonate initially injected (m 1) is known, as is the weight of each core segment (mCi). SPEJ P. 349^

scholarly journals GEODYNAMICS

GEODYNAMICS ◽  
2011 ◽  
Vol 1(10)2011 (1(10)) ◽  
pp. 94-102
Author(s):  
M. Yu. Nesterenko ◽  
◽  
A. Kleinаs ◽  
Y.M. Vikhot ◽  
A.B. Bodnarchuk ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Klinkenberg Effect ◽  
Reservoir Properties ◽  
Rock Permeability ◽  
Oil Saturation ◽  
Oil Displacement ◽  
Coastal Marine ◽  
Maximum Coefficient ◽  
Secondary Oil Recovery ◽  
Porosity Changes

According to the results of litho-petrographic investigations the rock reservoirs discovered by Lyzhiay-1 (2129 m), Vezhaiciay-11 (2046,8 m ) boreholes were formed under the coastal-marine conditions, and discovered by the Lyzhiay-1 (2127,6 m) borehole they were formed under the sea shelf conditions. Matrix of the rocks is characterized by high reservoir properties: permeability (taking into consideration the Klinkenberg effect) changes from 0,1×10-15 м2 to 80,1×10-15 м2 and open porosity changes from 4,1 to 13,3 %. The experiment has shown that in relation to the volume of effective pores and depending on the level of rock permeability, the structure of oil saturation is the following: free oil – 34–67 %, film oil – 30–41 %, absorbed oil – 2–30 %. The coefficient of water-oil displacement during waterless period is 0,34–0,67 and the maximum coefficient with the usage of secondary oil recovery enhancement methods during watering is 0,46-0,77.

Pore-Scale Oil Connectivity and Displacement by Controlled-Ionic-Composition Waterflooding Using Synchrotron X-Ray Microtomography

SPE Journal ◽  
2021 ◽  
pp. 1-8
Author(s):  
Tianzhu Qin ◽  
Paul Fenter ◽  
Mohammed AlOtaibi ◽  
Subhash Ayirala ◽  
Ali AlYousef
Keyword(s):  
Oil Recovery ◽  
Carbonate Rock ◽  
Early Stage ◽  
Ionic Composition ◽  
Sulfate Concentration ◽  
Pore Scale ◽  
X Ray ◽  
Ion Concentrations ◽  
Oil Displacement ◽  
The Impact

Summary Controlled-ionic-composition waterflooding is an economic and effective method to improve oil recovery in carbonate oil reservoirs. Recent studies show controlling the salinity and ionic composition of injection water can alter the wettability of carbonate mineral surfaces. The pore-scale oil connectivity and displacement by controlled-ionic-composition waterflooding in heterogeneous carbonate reservoirs, especially at the early stage, is still unclear. The goal of this study is to examine the role of ion concentrations and types in the oil displacement efficiency and investigate the impact of the waterflooding on the pore-scale oil displacement using the national synchrotron facility. A carbonate rock sample was flooded with synthetic high-salinity water and other water solutions with different sulfate concentrations. The waterflooding processes were visualized with synchrotron X-ray microtomography to follow the evolution of pore-scale oil/brine interactions at typical field flow rates. Experimental results show that the water with lower sulfate concentration and higher salinity did not change the wettability of the pore surfaces. Higher sulfate ion concentrations in the water, in contrast, altered the wettability of carbonate pore surfaces from oil-wet to neutral-wet within the first few minutes of waterflooding. Novel insight was gained on the ability of water with high-sulfate concentration to displace oil in the small pores and through abundant oil channels, which could consequently lead to higher oil recovery from the carbonate rock.

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