Fractured Cores Research Articles

Design and implementation of a shearing apparatus for the experimental study of shear displacement in rocks.

Fluid flow in the subsurface is not well understood in the context of "impermeable" geologic media. This is especially true of formations that have undergone significant stress fluctuations due to injection or withdrawal of fluids that alters the localized pressure regime. When the pressure regime is altered, these formations, which are often already fractured, move via shear to reduce the imbalance in the stress state. While this process is known to happen, the evolution of these fractures and their effects on fluid transport are still relatively unknown. Numerous simulation and several experimental studies have been performed that characterize the relationship between shearing and permeability in fractures; while many of these studies utilize measurements of fluid flow or the starting and ending geometries of the fracture to characterize shear, they do not characterize the intermediate stages during shear. We present an experimental apparatus based on slight modifications to a commonly available Hassler core holder that allows for shearing of rocks, while measuring the hydraulic and mechanical changes to geomaterials during intermediate steps. The core holder modification employs the use of semi-circular end caps and structural supports for the confining membrane that allow for free movement of the sheared material while preventing membrane collapse. By integrating this modified core holder with a computed tomography scanner, we show a new methodology for understanding the interdependent behavior between fracture structure and flow properties during intermediate steps in shearing. We include a case study of this device function which is shown here through shearing of a fractured shale core and simultaneous observation of the mechanical changes and evolution of the hydraulic properties during shearing.

Sodium silicate gelants for water management in naturally fractured hydrocarbon carbonate formations

Two commercially available, water-soluble, environmentally friendly, sodium silicate gelant systems (Silicate A and Silicate B) are screened and evaluated for water management applications in naturally fractured carbonate (NFC) reservoirs. The gelant impact on oil production and the ability to reverse poorly deployed gel treatments through gel dissolution are also investigated.Several bulk- and core-based tests are engaged, with the two investigated water-soluble silicate gelant chemicals having undergone a thorough and careful investigation of their filterability, injectivity, gelation time, gel strength, and gel shrinkage. The activators used for gel formation are system dependent and included NaCl, HCl, HNO3, HCOOH, and urea. Gelation is mainly controlled by the activator type and concentration, silicate concentration and temperature. Formed gel strength can be improved by increasing the injected silicate concentration but in Silicate B experiments, gelation difficulties are experienced for concentrations exceeding ∼7wt%.Filterability of Silicate B is significantly better than that of Silicate A. Fractured core tests using Silicate A gelant revealed that the average core permeability is reduced by three orders of magnitude from prior- to post-gelation conditions. Silicate B gelants exhibited gelling “difficulties” and formed gels displayed a lower strength compared to Silicate A gels. Unsuccessfully deployed gels may be reversed through dissolution with alkaline fluids (NaOH or KOH); gel dissolution rate is a function of the alkaline fluid concentration and type of process followed.Overall, Silicate A outperforms Silicate B and shows promising properties for its potential utilization in field applications to control injected water in NFC formations.

High Resolution Core Scan Facility at BGRL-MoES, Karad, India

ABSTRACT A high-resolution, optical core scan laboratory has been set up at Borehole Geophysics Research Laboratory (BGRL), Ministry of Earth Sciences (MoES), Karad. The facility provides a DMT® CoreScan3 optical core scanner and digital drill core data management system for core logging and analysis since July 2016. High resolution images are being produced in 360° mode for detailed unwrapped full circumference of drill core or plane mode for top surface image of slabbed drill core. Planar images of fractured cores and cuttings are also obtained. Image resolution ranges from 5 pix/mm (∼16 megapixel equivalent) to 40 pix/mm (∼1024 megapixel equivalent) for mapping of ultra high resolution data. The scanned core images are combined to create a digital core library. The facility helps in core sample analysis, structural analysis, textural and grain-size analysis, geotechnical studies, and integration with geophysical log data.

Transport of iron nanoparticles through natural discrete fractures

The transport of nano scale iron particles (NIP) in fractures is of concern for remediation of both fractured aquifers and porous aquifers when hydro-fracking and flow in preferential pathways takes place. In this study the transport of various NIP in a natural discrete fractured chalk core was investigated and their mass recoveries calculated. Four different types of NIP were tested and characterized in two ionic strength (IS) solutions at a particle concentration of 100–200 mg/l. The effect of IS, stability (sedimentation rate), particle size, solution viscosity and stabilizer were studied. NIP stability ranged from 1 to 100% following 120 min of stability tests and recoveries ranged from about 6 to 69%. The stabilizer type and concentration were shown to have significant role in NIP recoveries, especially at increased IS. It was evident that gravitational stability is the most crucial factor dominating transport of NIP. Accordingly, stability tests were shown to be a reliable indicator of NIP mobility. The high recoveries of some NIP tested, combined with the lack of clogging effect illustrates the enhanced mobility of NIP in fractures. The wide range of recoveries indicates NIP transport manipulation potential in such media. We therefore suggest that application of NIP in contaminated fractures has considerable potential as a remediation measure. In order to achieve NIP distribution in the aquifer while avoiding leakage to the environment, NIP stabilizer concentration should be adjusted according to the site-specific hydrogeochemical properties of the contaminated media.

CT scanning and flow measurements of shale fractures after multiple shearing events

A shearing apparatus was used in conjunction with a Hassler-style core holder to incrementally shear fractured shale cores while maintaining various confining pressures. Computed tomography scans were performed after each shearing event, and were used to obtain information on evolving fracture geometry. Fracture transmissivity was measured after each shearing event to understand the hydrodynamic response to the evolving fracture structure. The digital fracture volumes were used to perform laminar single phase flow simulations (local cubic law with a tapered plate correction model) to qualitatively examine small scale flow path variations within the altered fractures. Fractures were found to generally increase in aperture after several shear slip events, with corresponding transmissivity increases. Lower confining pressure resulted in a fracture more prone to episodic mechanical failure and sudden changes in transmissivity. Conversely, higher confining pressures resulted in a system where, after an initial setting of the fracture surfaces, changes to the fracture geometry and transmissivity occurred gradually. Flow paths within the fractures are largely controlled by the location and evolution of zero aperture locations. A reduction in the number of primary flow pathways through the fracture, and an increase in their width, was observed during all shearing tests.

Tertiary-CO2 flooding in a composite fractured-chalk reservoir

This paper presents the oil recovery mechanism by tertiary-CO2 flooding in a composite fractured chalk core. We perform two different core flooding experiments at reservoir conditions. We evaluate the efficiency of tertiary-CO2 flooding in different conditions, taking into account the effect of capillary continuity, water composition, and the heterogeneity.The composite core consists of six core plugs placed vertically in-line in the core holder with total length of 45 cm and average diameter of 3.74 cm. We use qualitative filter paper between each core plug to reserve the capillary continuity at reservoir conditions (258 bara and 110 °C). The “fracture” is represented by a centralized axial hole with a diameter of 0.6 cm. In all experiments, the composite fractured core is initially saturated with North Sea Chalk Field (NSCF) stock tank oil (STO) and synthetic connate water. Once the reservoir conditions are established, brine is injected from the bottom of the fracture and the oil is produced from the top. We stop water flooding (WF) after no more oil is being produced. CO2 is then injected from the top of the fracture and the oil is produced from the bottom.Experiments Exp-1C and Exp-2C utilize Sigerslev outcrop chalk cores. To account for the effect of initial water composition during WF, system is initially saturated with synthetic sea water with considerable amount of sulfate instead of formation water in Exp-1C. Whereas, we employ synthetic formation water with zero sulfate content in Exp-2C.The results of experimental work are reproduced via validated compositional reservoir simulator with a tuned equation of state (EOS). We develop an automated history matching algorithm to match the experimental data of WF and CO2 flooding (CF) periods.We observe a major impact of the initial water composition that results in strong- to moderate-spontaneous imbibition during WF period. Moreover, both experiments and simulations show that the tertiary CO2 recovery is significantly affected by the water saturation in the core after the secondary WF. We conduct a sensitivity analysis to study different CO2 injection scenarios such as in a single block, in a composite core with capillary continuity, and in a composite core with horizontal fractures in between. The results show the oil recovery during tertiary-CO2 flooding is barely affected by the degree of the capillary contacts between the chalk matrixes. Moreover, it is found that the mass transport during CF is mainly covered by diffusion rather than the convective flux or viscous forces.We build a modeling framework that accounts for proper modeling of imbibition and diffusion dominated processes in a composite chalk system at reservoir conditions.

Experiments on acoustic measurement of fractured rocks and application of acoustic logging data to evaluation of fractures

Fractures in oil and gas reservoirs have been the topic of many studies and have attracted reservoir research all over the world. Because of the complexities of the fractures, it is difficult to use fractured reservoir core samples to investigate true underground conditions. Due to the diversity of the fracture parameters, the simulation and evaluation of fractured rock in the laboratory setting is also difficult. Previous researchers have typically used a single material, such as resin, to simulate fractures. There has been a great deal of simplifying of the materials and conditions, which has led to disappointing results in application. In the present study, sandstone core samples were selected and sectioned to simulate fractures, and the changes of the compressional and shear waves were measured with the gradual increasing of the fracture width. The effects of the simulated fracture width on the acoustic wave velocity and amplitude were analyzed. Two variables were defined: H represents the amplitude attenuation ratio of the compressional and shear wave, and x represents the transit time difference value of the shear wave and compressional wave divided by the transit time of the compressional wave. The effect of fracture width on these two physical quantities was then analyzed. Finally, the methods of quantitative evaluation for fracture width with H and x were obtained. The experimental results showed that the rock fractures linearly reduced the velocity of the shear and compressional waves. The effect of twin fractures on the compressional velocity was almost equal to that of a single fracture which had the same fracture width as the sum of the twin fractures. At the same time, the existence of fractures led to acoustic wave amplitude attenuations, and the compressional wave attenuation was two times greater than that of the shear wave. In this paper, a method was proposed to calculate the fracture width with x and H, then this was applied to the array acoustic imaging logging data. The application examples showed that the calculated fracture width could be compared with fractures on the electric imaging logs. These rules were applied in the well logs to effectively evaluate the fractures, under the case of no image logs, which had significance to prospecting and development of oil and gas in fractured reservoirs.

Fracture Conductivity Modelling in Experimental Shale Rock Interactions with Aqueous CO2

In large scale subsurface injection of carbondioxide (CO2) as obtainable in carbon sequestration programs and in environmentally friendly hydraulic fracturing processes (using supercritical CO2), long term rock-fluid interaction can affect reservoir and seal rocks properties which are essential in monitoring the progress of these operations. The mineralogical components of sedimentary rocks are geochemically active particularly under enormous earth stresses, which generate high pressure and temperature conditions in the subsurface. While geomechanical properties such as rock stiffness, Poisson's ratio and fracture geometry largely govern fluid flow characteristics in deep micro-fractured formations. Simulation results suggested that influx-induced mineral dissolution/precipitation reactions within clay-based sedimentary rocks can continuously close micro-fracture networks, though injection pressure and effective-stress transformation first rapidly expand the fractures. This experimental modelling research investigated the impact of in-situ geochemical precipitation on conductivity of fractures under geomechanical stress conditions. Bulk rock geomechanical hardness was determined using Vickers’ micro-indentation. Differential pressure drop data across fractured composite core were also measured with respect to time over a five day period. This was used in estimating the conductivity of the artificially fractured cores with 25μm-bore microtubings embedded. Three experimental runs per sample types were carried out in order to check the repeatability of observed changes. The results showed that most significant diagenetic changes in shale rocks after flooding with CO2-brine, reflect in the effluent fluid with predominantly calcium based minerals dissolving and precipitating under experimental conditions. Micro-indentation results suggested slight reduction in the hardness of the shale rocks and this reduction appears dependent on diagenetic quartz content. Estimated fracture conductivity indicated that reactive transport of dissolved minerals can occlude micro-fracture flow paths, thereby improving caprock seal integrity with respect to leakage risk under CO2 sequestration conditions.

Digital coal: Generation of fractured cores with microscale features

Coal is highly heterogeneous at multiple scales, such that the characterisation of coal lags behind that of conventional reservoir rocks. This paper demonstrates the capability of a digital coal model that can be used to characterise the multiscale structure of coal as well as its petrophysical properties at the core scale (cm). X-ray micro-computed tomography (micro-CT) is applied to obtain the internal cleat structure of a heterogeneous fractured coal sample, based on which statistics of coal lithotype distributions and cleat geometrical properties are extracted. Digital coal models are constructed stochastically according to the measured statistics. Resulting models preserve the core scale (cm) heterogeneity and pore scale (µm to mm) cleat properties of the imaged coal sample. Furthermore, petrophysical evaluation is performed based on the stochastic digital coal models. We find that the generated digital coal models can provide permeability estimation with errors of 26.7% in comparison to that of the original micro-CT data. Since the presented model is able to preserve the multiscale heterogeneities as well as petrophysical properties of coal, our work provides an alternative to segmented micro-CT images. Therefore, we can avoid the challenges that are inherent to micro-CT images, such as segmentation errors, size and resolution limitations. The digital coal model can also be a tool of linking the rock microstructure to petrophysical properties at the core scale, such that we can predict the permeability of coal based on its geometrical measures rather than expensive laboratory experiments.

Experimental investigation of acid imbibition on matrix and fractured carbonate rich shales

Matrix and fracture permeability of carbonate rich tight cores from Niobrara, Bakken, and Three Forks formations were measured before and after exposing the core samples to spontaneous imbibition using 10 wt % KCl and 1 wt % HCl acid. A hydraulic fracture was modeled by saw-cutting a given core sample. Sand proppant of 0.02 lbs/ft2 concentration and 30/80 mesh size with monolayer packing was used for the propped fracture cores. Permeability was measured at varying net stress of 1000 psia up to 6000 psia. Before and after dilute HCl acid imbibition matrix and fracture permeability vs. stress and rock hardness measurements were investigated. Brine and dilute acid imbibition effect on proppant embedment, rock softening/weakening, and fracture roughness were assessed. Brine imbibition before and after dilute acid imbibition was also studied to investigate possible wettability alteration.After acid soaking/imbibition, up to twenty fold increase in matrix permeability was observed for carbonate rich Niobrara cores. A matrix permeability decrease was observed in clay rich Three Forks cores. On the other hand, permeability decrease after dilute HCl acid imbibition was observed on both propped and un-propped fractured Niobrara cores. Matrix permeability increase after acid imbibition is attributed to the enhancement of pore throat connectivity and nano- and micro-fracture etching. Permeability decrease for the un-propped fractured Niobrara cores is attributed to fracture surface softening leading to decrease in fracture roughness and fracture aperture at in-situ stress conditions. And, permeability decrease for the propped fracture cores is attributed to decrease in fracture width or aperture caused by proppant embedment as brine and acid weakens the fracture face fabric. It is concluded that dilute acid injection of pre and post hydraulic fracturing stimulation in ultra-tight carbonate rich mudrocks could improve the overall deliverability of stimulated reservoir volume. This is because, despite decrease in fracture permeability after acid imbibition, matrix permeability increase is more significant for the overall deliverability of ultra-tight carbonate rich mudrocks. Moreover, favorable wettability alteration can be achieved by dilute acid imbibition.

Study on gas-liquid relative permeability experiments of fractured-porous reservoirs

Abstract For carbonate reservoirs, gas-water and oil-gas relative permeability curve are of importance for parameters calculation in oil-field development, dynamic analysis and numerical reservoir simulation. The oil-gas/gas-water relative permeability curves were measured with unstable method under normal temperature and low pressure, using fifteen artificial fractured cores. The shape and change characteristics of gas/water and oil/gas relative permeability curve were mainly analyzed. The results showed that for the relative permeability curve of water driving gas. The saturation of equal permeability point, the saturation range of two-phase flow region and the displacement efficiency has a good power-function relation with core permeability. In addition, the saturation of equal permeability point, the saturation range of two-phase flow region and the displacement efficiency will decrease with the increasing of core permeability. However, for oil-gas relative permeability curves, the saturation of equal permeability point, the saturation range of two-phase flow region and the displacement efficiency will increase with the increasing of core permeability. It should be noted that the gas relative permeability presents a straight line in the normalized relative permeability curve, which indicates that the main flow is dominated by fracture with low displacement efficiency. The research results provide theory basis for fracture-vuggy carbonate reservoir development and new research idea for the further study of this kind of reservoir.

Computed-Tomography-Scan Monitoring of Foam-Based Chemical-Enhanced-Oil-Recovery Processes in Fractured Carbonate Cores

Summary Waterflooding is often inefficient in carbonate reservoirs because of the presence of fractures and unfavorable wettability. Oil recovery can be improved by enhancing the following drive mechanisms: Capillary imbibition with wettability modifiers Viscous drive by increasing the pressure gradient in the fracture network Water/oil gravity drainage with low-interfacial-tension (IFT) surfactant formulations that also reduce oil trapping This paper presents an experimental approach that evaluates different chemical-enhanced-oil-recovery (EOR) alternatives on the basis of one or several of the three aforementioned recovery mechanisms. The experiments consist of injecting an aqueous chemical solution or a foam containing chemical additives into an artificially fractured carbonate core. The imbibition is monitored with a recent computed-tomography (CT) scanner allowing the local quantitative monitoring of three phases, including accurate quantification of matrix oil recovery. This paper is mainly focused on the impacts of foaming agents and wettability modifiers (WMs), implemented separately or jointly. The experiments have been conducted on several cores of different permeability, resulting in various permeability contrasts between matrix and fracture. A major result concerns the kinetics of oil recovery by chemical additives that is greatly increased when a viscous drive is applied across the matrix medium by means of the circulation of foam in the fracture. Experiments in fractured cores of different permeabilities indicate that foam does not penetrate the matrix, but drives the chemical aqueous phase into the matrix because of the generated pressure gradient. Detailed analysis of oil-mobilization dynamics is provided. These foam-flow experiments are compared with a former chemical imbibition test on a nonfractured core for further insight into the role played by viscous forces. The comparison of tested recovery scenarios leads to conclusions regarding optimal chemical-EOR strategies for naturally fractured carbonate reservoirs with poor secondary-recovery prognosis.

Enhanced oil recovery by air-foam flooding system in tight oil reservoirs: Study on the profile-controlling mechanisms

A one-dimensional long core displacement experiment was designed based on injection of pure foam liquid, air, and air-foam system into the tight matrix core and fracture core. This aimed to verify the individual injection capacity of these materials in the ZenPing well area in a typical tight oilfield, China. The results indicate that the air-foam system cannot be injected directly into the tight matrix core. However, because some of the foaming agent is absorbed by the reservoir rock, causing foam collapse, the defoamed liquid and separated air can flow into the tight matrix core, which results in stable displacement. Three-core parallel displacement experiments were designed, including two matrix cores (with permeability difference ratios of 10) and one fractured core. The results indicated that the air-foam system mostly flows into the fractured core and blocks the fractures. Thereby, some of the defoamed liquid and separated air could flow into the matrix core to displace the residual oil. The residual oil saturation and the oil displacement efficiency were 21.12% lower and 32.89% higher, respectively, than those of water flooding. We also analyzed the profile-controlling mechanisms, which indicated the air-foam system flooding is capable of improving performance following water flooding. We recommend that water flooding should be switched to air-foam system flooding as early as possible before the water cut reaches around 90%. Our findings were successfully used to guide a pilot test of the ZenPing well area. The results indicate that air-foam flooding is a feasible means for improving oil recovery in tight oil reservoirs.

Experimental Investigation of Crack Extension Patterns in Hydraulic Fracturing with Shale, Sandstone and Granite Cores

Hydraulic fracturing is an important method of reservoir stimulation in the exploitation of geothermal resources, and conventional and unconventional oil and gas resources. In this article, hydraulic fracturing experiments with shale, sandstone cores (from southern Sichuan Basin), and granite cores (from Inner Mongolia) were conducted to investigate the different hydraulic fracture extension patterns in these three reservoir rocks. The different reactions between reservoir lithology and pump pressure can be reflected by the pump pressure monitoring curves of hydraulic fracture experiments. An X-ray computer tomography (CT) scanner was employed to obtain the spatial distribution of hydraulic fractures in fractured shale, sandstone, and granite cores. From the microscopic and macroscopic observation of hydraulic fractures, different extension patterns of the hydraulic fracture can be analyzed. In fractured sandstone, symmetrical hydraulic fracture morphology could be formed, while some micro cracks were also induced near the injection hole. Although the macroscopic cracks in fractured granite cores are barely observed by naked eye, the results of X-ray CT scanning obviously show the morphology of hydraulic fractures. It is indicated that the typical bedding planes well developed in shale formation play an important role in the propagation of hydraulic fractures in shale cores. The results also demonstrated that heterogeneity influenced the pathway of the hydraulic fracture in granite cores.

La revue dans le prisme de la réingénierie

Drilling fluid losses are challenging to prevent or mitigate during drilling. Lost circulation treatments are applied to stop losses using a corrective approach or to hinder losses using a preventive approach, also known as wellbore strengthening. The key factors that must be determined when treating losses are the fracture width and the required particle size. The fracture width is often estimated using analytical fracture models. In this paper, five different fracture width models were analyzed and compared to hydraulic fracturing experiments. The hydraulic experiments were conducted on impermeable concrete cores to investigate the effect of adding lost circulation materials (LCM) to enhance the fracture breakdown pressure and the fracture re-opening pressure. The results showed that adding LCM blends enhanced the breakdown pressure up to 18% and the re-opening pressure up to 210%. The cores that were fractured with fluid-containing solids had a larger fracture width compared to the fractured cores using base fluid. Comparing the measured fracture widths from experiments with analytical models showed a discrepancy in the fracture width estimation for all of the models and the experiments, except for one model.

Analysis of analytical fracture models for wellbore strengthening applications: An experimental approach

Drilling fluid losses are challenging to prevent or mitigate during drilling. Lost circulation treatments are applied to stop losses using a corrective approach or to hinder losses using a preventive approach, also known as wellbore strengthening. The key factors that must be determined when treating losses are the fracture width and the required particle size. The fracture width is often estimated using analytical fracture models. In this paper, five different fracture width models were analyzed and compared to hydraulic fracturing experiments. The hydraulic experiments were conducted on impermeable concrete cores to investigate the effect of adding lost circulation materials (LCM) to enhance the fracture breakdown pressure and the fracture re-opening pressure. The results showed that adding LCM blends enhanced the breakdown pressure up to 18% and the re-opening pressure up to 210%. The cores that were fractured with fluid-containing solids had a larger fracture width compared to the fractured cores using base fluid. Comparing the measured fracture widths from experiments with analytical models showed a discrepancy in the fracture width estimation for all of the models and the experiments, except for one model.

Influence of heteroaggregation processes between intrinsic colloids and carrier colloids on cerium(III) mobility through fractured carbonate rocks

Colloid facilitated transport of radionuclides has been implicated as a major transport vector for leaked nuclear waste in the subsurface. Sorption of radionuclides onto mobile carrier colloids such as bentonite and humic acid often accelerates their transport through saturated rock fractures. Here, we employ column studies to investigate the impact of intrinsic, bentonite and humic acid colloids on the transport and recovery of Ce(III) through a fractured chalk core. Ce(III) recovery where either bentonite or humic colloids were added was 7.7–26.9% Ce for all experiments. Greater Ce(III) recovery was observed when both types of carrier colloids were present (25.4–37.4%). When only bentonite colloids were present, Ce(III) appeared to be fractionated between chemical sorption to the bentonite colloid surfaces and heteroaggregation of bentonite colloids with intrinsic carbonate colloids, precipitated naturally in solution. However, scanning electron microscope (SEM) images and colloid stability experiments reveal that in suspensions of humic acid colloids, colloid-facilitated Ce(III) migration results only from the latter attachment mechanism rather than from chemical sorption. This observed heteroaggregation of different colloid types may be an important factor to consider when predicting potential mobility of leaked radionuclides from geological repositories for spent fuel located in carbonate rocks.

Experimental study of gas–oil relative permeability curves at immiscible/near miscible gas injection in highly naturally fractured reservoir

The main aim of this work is to investigate gas–oil relative permeability curves as the main flow function in different gas injection scenarios, immiscible and near miscible in case of highly fractured reservoirs.In this research, some experiments have been done on the reservoir core sample selected from sandstone formation in one of the Iranian naturally fractured oil reservoirs. The core is saturated with oil sample and CO2 is injected into oil saturated core sample. Experiments have been performed on both of the sandstone and artificial fractured sandstone, represented as no fractured and highly fractured reservoirs, based on incremental pressure algorithm approaching into near miscible condition. Inverse modeling method has been used to calculate relative permeability curves.By comparing the relative permeability curves in immiscible and near-miscible conditions, the results show that in sandstone core type this change is considerable, but in highly artificial fractured sandstone with a high ratio of artificial fractured to sandstone absolute permeability (Kef /Ks) is not substantial. Moreover the results show that in the described case of artificial fractured core type so simple conventional relative permeability methods have the same results compared to a sophisticated inverse modeling method. The other main result is the lack of miscibility activation in near miscible injection through the highly fractured reservoirs leading to viscose dominant flow rather than capillary.Finally by considering this changing behavior, a better knowledge of gas front movement through highly fractured reservoirs in low IFT regions can be obtained.

Visualization of Carbon Dioxide Enhanced Oil Recovery by Diffusion in Fractured Chalk

Summary This work demonstrates that diffusion may be a viable oil-recovery mechanism in fractured reservoirs during injection of carbon dioxide (CO2) for enhanced oil recovery, depending on the CO2 distribution within the fracture network and distance between fractures. High oil recovery was observed during miscible, supercritical CO2 injection (RF = 86% original oil in place) in the laboratory with a fractured chalk core plug with a large permeability contrast. Dynamic 3D fluid saturations from computed-tomography (CT) imaging made it possible to study the local oil displacement in the vicinity of the fracture, and to calculate an effective diffusion coefficient with analytical methods. The obtained diffusion coefficient varies between 0.83 and 1.2 ×10−9m2/s, depending on the method used for calculation. A numerical sensitivity analysis, with a validated numerical model that reproduced the experiments, showed that the rate of oil production during CO2 injection declined exponentially with increasing diffusion lengths from the CO2-filled fracture and oil-filled matrix. In a numerical upscaling effort, with the experimentally achieved diffusion coefficient, oil-recovery rates and local flow were studied in an inverted five-spot pattern in a heavily fractured carbonate reservoir.

Visualization and Analysis of Surfactant Imbibition Into Oil-Wet Fractured Cores

Summary Imbibition of surfactant solution into the oil-wet matrix in fractured reservoirs is a complicated process that involves gravity, capillary, viscous, and diffusive forces. The standard experiment for testing imbibition of surfactant solution involves an imbibition cell, in which the core is placed in the surfactant solution and the recovery is measured vs. time. Although these experiments prove the effectiveness of surfactants, little insight into the physics of the problem is achieved. In this study, we performed water and surfactant flooding into oil-wet fractured cores and monitored the imbibition of the surfactant solution by use of computed-tomography (CT) scanning. From the CT images, the surfactant-imbibition dynamics as a function of height along the core was obtained. Although the waterflood only displaced oil from the fracture, the surfactant solution imbibed into the matrix; the imbibition is frontal, with the greatest imbibition rate at the bottom of the core, and the imbibition decreases roughly linearly with height. Experiments with cores of different sizes showed that increase in either the height or the diameter of the core causes decrease in imbibition and fractional oil-recovery rate. We also perform numerical simulations to model the observed imbibition. On the basis of the experimental measurements and numerical-simulation results, we propose a new scaling group that includes both the diameter and the height of the core. We show that the new scaling groups scale the recovery curves better than the traditional scaling group.