Core Holder Research Articles

A New Workflow for Sampling and Digitizing Increment Cores.

Here we present a new workflow from taking increment cores in the field, storing and transporting them to the lab, to digitizing their tree rings for further analyses for subsequent dendroecological analyses. The procedure involves the use of new sample carriers for increment cores. These new Gärtner Schneider Core (GSC) holders are designed using three-dimensional (3D) modeling software and finally printed with a 3D printer. Using these mounts from the beginning in the field, the cores can directly be cut with a core microtome, and their surface can then be digitized without further rearrangement using a new high-resolution image-capturing system. They are thus available for direct analysis. This system allows digitizing tree rings from cores and disks, and also taking images from long micro sections (up to 40 cm) using transmitted light. This feature is of special interest for dendroecological and geomorphic applications to identify the onset of any disturbance in micro sections cut with a core-microtome.

Comparative evaluation of pore volume compressibility of carbonate reservoir rocks: different laboratory measurement approaches

The pore volume compressibility (C PV) of a reservoir plays an essential role in estimating the reserve oil and recovery factor. Therefore, selecting an appropriate laboratory measurement approach for determining the C PV is crucial. This study aims to compare three different routine approaches to C PV measurement. Fifty-eight carbonate core plug samples with diverse porosity from the Sarvak Formation in the Southwest of Iran were selected. The measurements were performed at different saturation, pressure, and temperature conditions in triaxial core holders. Results show that samples with the lowest porosity have the highest compressibility value, and samples with the highest porosity have the lowest value. Furthermore, the compressibility measured on brine-saturated cores at pressure and temperature conditions was higher than only brine-saturated, and consequently higher than dry core plugs. Hence, the measurement methods and approaches severely affect the resultant compressibility. The values obtained at representative reservoir conditions are advised to be utilized in simulation and modeling studies. A novel reciprocal model was also proposed to appropriately correlate the data with porosity. The results of this work give insight into the selection of the best laboratory measurement approach to estimate the actual C PV value in reservoir conditions, especially at varying pore pressure and temperature.

PENGARUH POLIMER PC DENGAN ADDITIF TWEEN-80 TERHADAP KARAKTERISTIK POLIMER DAN RECOVERY FACTOR PADA MINYAK 39 °API DI BATUAN SANDSTONE

Background: The increasing demand for petroleum and the depletion of oil reserves in oil fields require the development of more efficient oil recovery techniques to enhance oil production. One method that can be employed is Enhanced Oil Recovery (EOR), where chemical injection becomes a viable approach. One chemical injection method that can be used is polymer injection. One suitable polymer for this purpose is cellulose polymer (PC). Cellulose polymer (PC) is the most abundant polymer in nature, a renewable material that is degradable, biocompatible, cost-effective, and non-toxic. Cellulose can be derived from plants and certain types of bacteria.Objective: This research aims to investigate the influence of temperature variations on cellulose polymer (PC) with Tween-80 additive on the Recovery Factor.Methodology: Laboratory experiments were conducted using the core flooding technique with a core holder, applying the slug method with various °API variations on light crude oil with an API gravity value of 39. Sandstone rock samples were used in the experiments, prepared by saturating with brine and oil.Result: The laboratory results showed a recovery percentage of 7.89% at a temperature of 60 °C and 17.86% at a temperature of 80 °C. The highest increase in oil recovery was observed at a temperature of 80 °C, with a recovery factor of 17.86%. In conclusion:, based on the conducted core flooding experiments, the best recovery factor was found in polymer injection using PC with Tween-80 additive at a temperature of 80 °C.

Experimental study of asphaltene deposition during CO2 and flue gas injection EOR methods employing a long core

Gas injection is a well-known method for enhancing oil recovery (EOR). The utilization of greenhouse gases, such as carbon dioxide (CO2) or flue gas, offers the dual advantage of reducing greenhouse gas emissions while potentially enhancing the sweep efficiency in oil recovery. Nevertheless, one of the notable challenges encountered when using these gases is the precipitation and deposition of asphaltenes, leading to formation damage and a decrease in reservoir permeability, particularly in the case of light oil reservoirs. In this study, CO2 and flue gas were injected into an elongated core sample comprising four individual core plugs under reservoir conditions to displace the light live oil. The recovery factor and asphaltene deposition along the core holder were assessed and compared as two crucial parameters within the gas injection scenario. Our results indicate a significantly higher recovery factor of 86% achieved with CO2 injection compared to 36% with flue gas injection, attributable to differences in their interfacial tension and miscibility. However, the CO2 injection method exhibits more pronounced formation damage. Individual assessment of each core plug reveals that permeability impairment is most acute in the initial two core plugs, situated closer to the injection face of the extended core. These findings enhance our understanding of the mechanisms contributing to permeability impairment resulting from asphaltene deposition during CO2 and flue gas injection for EOR.

In-situ emulsification in low-tension surfactant/polymer systems: Impacts on enhanced oil recovery

The flow of two immiscible liquids in porous media can lead to fluid mixing, resulting in emulsions—where one phase is dispersed as droplets in the other. In reservoir rocks, natural surfactants and polar molecules, like asphaltenes, can promote oil–water emulsion formation. During chemically enhanced oil recovery processes (CEOR) such as surfactant, alkali, or surfactant-alkali flooding, in-situ emulsification is often seen as key to enhancing frontal stability and facilitating the piston-like displacement of oil by water. However, this work reports a minimal effect of in-situ emulsification on oil production during surfactant-polymer (SP) flooding. Experimental studies show this by injecting prepared emulsions into a multi pressure-tap core holder and examining emulsion formation in one reservoir core before moving it into a second core for oil displacement. This helps us understand the specific role of emulsions in oil mobilization. Factors like surfactant concentration, interfacial tension, and the timing of introducing the surfactant-polymer solution do influence the intensity of in-situ emulsification. Yet, the incremental oil recoveries show no significant differences. Through similar experiments, it is observed that ultra-low interfacial tension (IFT) in our surfactant-polymer system is the primary mechanism for oil mobilization. The slight increase in pressures suggests that in-situ emulsification has a limited role in increasing flow resistance during the ultra-low IFT SP flood process, potentially not improving the swept volume. This research can guide the development of systematic approaches to analyze the effects of in-situ emulsification on oil mobilization and evaluate chemical flooding processes.

Study Evaluates CO2 Storage Potential During CO2 Mobility-Control Optimization

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 212969, “Evaluation of CO2 Storage Potential During CO2 Mobility-Control Optimization for Enhanced Oil Recovery,” by Alvinda Sri Hanamertani, SPE, Ying Yu, SPE, and Omar El-Khatib, SPE, University of Wyoming, et al. The paper has not been peer reviewed. _ CO2 mobility control through foam technology has enabled better sweep efficiency and, consequently, better oil productivity during enhanced oil recovery (EOR) processes. Along with enhancing oil production, a sound potential exists for in-situ generated foam to enhance CO2 storage. However, the effect of the different in-situ foam generation strategies on the combined goal of maximum oil production and carbon storage is not well elucidated in the literature. In the complete paper, the authors methodically evaluate the simultaneous optimization of CO2 storage and oil recovery using multiple injection strategies. Introduction The current investigation is a continuation of two previous studies that provided a methodology for screening and using foaming agents for optimized CO2 storage in sandstone and carbonate formations. A base case of tertiary CO2 flooding was established for comparison with in-situ foam generation by two approaches: single-cycle surfactant-alternating-gas (SAG) flooding and coinjection of CO2 and surfactant. Additionally, the effect of surfactant concentration on foam efficiency, CO2 storage capacity, and oil recovery were evaluated in both approaches at reservoir conditions. Materials and Methods Fluids and Porous Medium. In this study, a synthetic brine with total dissolved solids of 20 wt% was used as blank brine and laden with a commercial zwitterionic surfactant that was used to prepare surfactant solutions with concentrations of 0.5 and 1 wt% active matter in the synthetic brine. Three core plugs were drilled from an Indiana limestone outcrop block. The cores were then cleaned and oven-dried at 95°C. Experimental Procedure. Vacuum saturation with brine was commenced for the three cores. The porosity of the cores was calculated using their dry and brine-saturated weights. Then, the 100% brine-saturated core was placed in a core holder and loaded into an oven set to 90°C. The pore pressure was fixed at 2,000 psi, and the confining pressure was controlled at 3,000 psi throughout the flooding experiment. The brine permeability of the core samples was evaluated by measuring the pressure drop across the core at different brine-injection flow rates. In the first experiment (IL1), oil drainage with a flow rate of 0.2 cm3/min was performed to establish irreducible water saturation of 46.9%. This total flow rate was kept the same throughout the three experiments. Then, a waterflooding stage was begun and the oil recovery was recorded. After reaching a plateau in oil recovery, supercritical CO2 (scCO2) was injected during the EOR process until the oil production plateaued.

Optimization of enhanced oil recovery using ASP solution

Many studies have been conducted to focused on developing an optimal alkali/surfactant/polymer (ASP) composition to increase the recovered fraction of oil in reservoirs that have already undergone water injection. To analyze the effect of alkali (Na2CO3), surfactant (lauryl sodium sulfate), and polymer (commercial xanthan gum) concentration on oil recovery, a complete factorial experimental design was performed with combinations of three variables (alkali, surfactant, and polymer) and three central point replications (2³ + 3). The experiments were carried out on a core holder using rock samples from the Botucatu formation. The simulated oil reservoirs have an average permeability of 348 mD and a temperature of 60 °C. The crude oil was acquired from the Carmópolis field, with 25.72 °API. Synthetic production water containing 40,000 mg L−1 of NaCl and 13,000 mg L−1 of Na2SO4 was injected through an HPLC pump to saturate the rock samples and to recover the oil in the secondary step. From the experimental results, it was verified that the surfactant and polymer concentrations are the most statistically significant independent variables and that first-order interactions are not statistically significant for the process. The oil recovery factors in the secondary stage ranged between 30 and 36 % of the OOIP, which are within the range reported in the literature. The optimal composition of the ASP fluid obtained a recovered fraction of oil of 62 % in the advanced step. Other combinations reported in the literature used higher concentrations of alkali, surfactant, and polymer with lower recoveries and higher cost in the injection design. Thus, the present study highlights the necessity to investigate the performance of each component of the ASP solution. In addition, the results obtained in this study are very attractive for possible full-scale applications.

Experimental investigation of CO2-CH4 core flooding in large intact bituminous coal cores using bespoke hydrostatic core holder

This paper presents the CO2-CH4 core flooding and permeability studies conducted with large intact coal core samples. A bespoke core holder was designed and commissioned to conduct the core flooding experiments. The CO2 and CH4 core flooding experiments were performed to understand the CH4 displacement efficiency of CO2 from the coal cores and the permeabilities of CO2 and CH4 during the core flooding. The CO2-CH4 gas displacement experiments were performed on intact coal cores of 9.9 cm in diameter with varying lengths to make up 60 cm-long cores that were extracted from coal blocks using a diamond core-drilling machine. The CO2 and CH4 core flooding experiments were conducted using the core holder at maximum of 1450 psi confining pressures and at 298.15 K. A constant gas flow rate of 1 mL/min was maintained to flood the core with an outlet backpressure set at 25 to 30 ± 2 psi. The core holder is equipped with two differential pressure taps to measure the pressure change along the core length to measure the differing permeability along the core lengths which is difficult to observe in the smaller size intact samples. Both coals, EMB and ZM, showed favourable CH4 displacement efficiencies of CO2 about 96.5% and 99.7%, respectively. The dependency of the core lengths on the permeability measurements is more pronounced in the results obtained in the current study. The results indicated a decreasing trend in CO2 permeability and increasing CH4 permeability during CO2 injection. The observation indicated CO2 adsorption and CH4 displacement. Overall, the core flooding experiments improved the current understanding of CO2-CH4 core flooding by showing the core size dependence in permeability measurement experiments. In contrast to the single species CO2 flow experiments, the permeability variation during the CO2-CH4 flooding and the CH4 sweeping efficiency of CO2 provided insights into the CO2-ECBM operational design.

Continuous measurement of gas permeability in non-homogeneous hydrate reservoirs under effective pressure via a novel apparatus

Gas permeability is a key physical parameter to determine the exploitation efficiency of natural gas hydrate (NGH). However, the relevant research mainly focuses on the permeability of homogeneous hydrate reservoirs, there have been no studies of non-homogeneous hydrate reservoirs. Therefore, a novel permeability measurement apparatus was designed in this study, which used two core holders in parallel to achieve the spatio-temporal continuous measurements of gas permeability for non-homogeneous reservoirs. Marine soils obtained from the South China Sea were used to remold the non-homogeneous hydrate reservoirs, including two homogeneous hydrate reservoirs with water saturation of 40% (reservoir A) and 80% (reservoir B), respectively. The constant gas flow of 0.5 ml/s and constant back pressure of 3 MPa was carried out to measure the gas permeability. The experimental results showed that the gas permeability measured in this work had similar regularities with other literature data. When the effective pressure increased from 1 MPa to 6 MPa, the permeability of reservoir A, reservoir B, and non-homogeneous hydrate reservoir decreased from 15.2 mD to 10.9 mD, 10.5 mD to 4.6 mD, and 12.5 mD to 8.5 mD, respectively. In addition, the variation in the non-homogeneous coefficient showed three stages: 1–2 MPa stage, 2–3 MPa stage, and 3–6 MPa stage. What's more, the permeability damage rate of non-homogeneous reservoirs increased by nearly 35% with the increase of effective pressure. These findings obtained by this apparatus will enhance the understanding of gas permeability in the non-homogeneous hydrate reservoirs, and guide further field exploitation of hydrate reservoirs.

Dynamic monitoring of saturation profiles during two phase immiscible displacements in confined sand packs using time-domain analysis of the frequency domain electromagnetic sweeps

Water saturation 1D spatial profiles were monitored using real-time domain analysis of the measured frequency domain complex reflection coefficients of electromagnetic sweeps during oil and deionized water flood experiments at ambient conditions. Gravity and viscous induced fingering and piston-like displacement scenarios were explored. A patented coaxial transmission line core holder was designed to host saturated sand packs compressed in their axial and radial dimensions. An inverse chirp z-transform algorithm was used to convert the measured responses from frequency to time domain. An optimization routine was developed to convert the resulting time domain step responses to water saturation profiles at every pore volume fraction of fluids injected. Advancing and trailing fronts and their breakthrough times were detected. Darcy's flow analysis was performed to extract 1D pressure distribution spatial profiles and dynamic capillary pressure curves for 3 drainage floods. The oil ganglia flow and gravity fluid separation were detected in water floods.

Using high pressure solutions of polyfluoroacrylate and CO2 to Seal cement cracks for improved wellbore integrity

Polyfluoroacrylate (PFA) is a hydrophobic and oleophobic polymer that is soluble in high pressure carbon dioxide (CO2). In this study, the ability of PFA-CO2 solutions to greatly reduce the apparent permeability of split or cracked Portland cement cylindrical samples is assessed. The apparent permeability values of confined samples were determined before and after treatment with PFA-CO2 solutions. In four tests, PFA-CO2 solutions were continuously displacing pure CO2 from the cracked cement and the decrease in apparent permeability due to PFA adsorption and wettability alteration was monitored. The lowest apparent permeability cracked cement sample (81 nD) was completely sealed with a very small amount of solution. Samples with initial apparent permeabilities of 89 μD and 29.4 mD exhibited 92% and 99% reductions in permeability, respectively, before the experiments had to be stopped because of the excessively large increase in pressure drop. A 50% reduction in apparent permeability was observed with a 3.80 mD sample. Four other split cement samples (bound together with tape) with an initial apparent permeability in the 9.0–70 mD range were removed from the core holder and immersed in a PFA-CO2 solution for 24 h to allow for PFA adsorption. Then the PFA-CO2 solution was depressurized, allowing for the deposition of additional PFA from the solution within the crack as the pressure fell below the cloud point pressure of the PFA-CO2 solution. These four samples were then confined again in a core holder and apparent permeability reductions of 29–93% were observed. Results from these eight experiments indicates that the more substantial reductions in the nD – mD apparent permeability of the cracked cement correlated to lower initial crack permeability, higher PFA concentration, and slower injection rate of the PFA-CO2 solution into the crack.

Dynamic monitoring of dielectric properties during two phase immiscible displacements in sand packs using frequency domain electromagnetic sweeps

Electromagnetic heating is a promising soil remediation method especially in thin formations. The lack of a wide-spread adoption of this method stems from insufficient knowledge of how the complex dielectric properties, that govern propagation of the electromagnetic waves through porous media, change with changing frequency, water saturation, displacement types and flow regimes. To breach these gaps several sets of spontaneous deionized (DI) water imbibition experiments, followed by the primary drainage floods, that were followed by the secondary DI water imbibition floods in confined uniform sand packs were performed. The frequency domain relative dielectric constant and conductivities were extracted from the two-port complex S-parameter measurements taken with the vector network analyzer during these immiscible displacements at various water saturation levels at ambient conditions. A novel coaxial transmission line core holder was designed and commissioned, and a modified version of a plane-invariant dielectric extraction algorithm was developed for this purpose. Series, parallel and semi-disperse mixing models were applied to fit the water saturation dependent relative dielectric constant and conductivity values sampled at 500 MHz from the extracted frequency domain spectra. The Maxwell-Garnett parallel model was proved to be the most flexible because it could capture the sampled conductivity values in all secondary imbibition floods before and after the breakthroughs, where the inflection points were observed. These inflection points were attributed to silica production and a potential shear-stripping flow. This observation was further confirmed by conducting a single-phase Darcy's law analysis of two DI water imbibition floods.

Hybrid Technique for Setting Initial Water Saturation on Core Samples

Relative permeability and capillary pressure are important parameters in reservoir simulations because it helps in understanding and anticipating oil and/or gas production scenarios over the years. They are both obtained in a laboratory after establishing the required initial conditions. As a matter of fact, before measuring imbibition relative permeability and capillary pressure, it is recommended to set initial rock reservoir conditions by establishing appropriate initial water saturation (Swi) and by aging the core to restore the reservoir wettability. There are several conventional techniques to establish Swi. Viscous flooding is a fast technique, but it may create a non-uniform saturation profile and, in some cases, be inefficient in reaching low Swi targets. Centrifugation is a capillary-driven technique that is also very fast; however, the possibility of not desaturating the outlet face is a significant constraint. In both cases, reversing flow direction is generally performed to flatten the saturation profile; however, this phenomenon is poorly controlled. The application of capillary pressure by porous plate allows targeting a specific value of Swi and generates a uniform saturation profile; however, it is a very time-consuming method. In this paper, we present the Hybrid Drainage Technique (HDT), which couples viscous flooding and porous plate approaches, significantly reducing the experimental duration when setting Swi. Another advantage of the method is the possibility of setting a uniform saturation profile at the targeted Swi. A specific core holder, adapted to nuclear magnetic resonance (NMR) imaging and capable of performing both viscous flooding and porous plate testing without unloading the rock, was designed. Using this core holder enables performing aging and imbibition coreflood testing with no further manipulation of the core sample. Monitoring saturation profiles was made possible by using an NMR imaging setup. The method has been tested and validated on two outcrop samples from Bentheimer (sandstone) and Richemont (limestone), drastically reducing the experimental time of the primary drainage step in comparison to classical porous plate drainage but also leading to uniform water saturation profiles. The experiment duration is reduced, and it enables the realization of coreflooding; therefore, this technique may be used for larger samples classically used in relative permeability experiments. This approach is preferred as it provides faster and more reliable measurements of saturation.

Integrating laboratory acoustic measurements, deep neural networks, and micro-CT imaging for characterizing rock brittle deformation

Brittle deformation is prevalent in both geological processes and engineered structures, so probing its actions is an important task as much for Earth materials and engineered ones. To characterize brittle deformation, acoustic waves are especially useful in revealing deformation processes. To promote the use of acoustic techniques, we present an integrated characterization approach that includes both acoustic data collection and analysis. By customizing a rock sample and acoustic sensor assembly, we incorporate acoustic data acquisition into a core holder system that accommodates relatively small samples (2.54 cm diameter) under triaxial loading. Along with fast and high-resolution acoustic waveform recording, the compact design facilitates convenient collection of high-quality acoustic data. To meet the challenge of efficiently and accurately picking P-wave arrivals for hundreds of thousands of acoustic waveforms, we modified and implemented a deep neural network model from the seismology literature called PhaseNet. After training with an augmented dataset of manually-picked arrivals (a total of around 50,000 waveforms), the modified PhaseNet model achieved more than 88% (96%) picking accuracy within ±1 μs (±2 μs) time residual relative to manual picks. This demonstrates the potential of integrating deep learning techniques into the workflow of acoustic data analysis for rapid and accurate extraction of valuable information from a large acoustic dataset. Finally, we conducted high-resolution micro-computed tomography (micro-CT) to inform and complement acoustic characterization at micron- and centimeter-scales. Microscopic observations validate the spatial development of two macroscopic fractures, and suggest that deformation-induced changes in velocity need to be incorporated for accurately locating microcracking events. Thus, integrating acoustic monitoring, a deep neural network, and micro-CT imaging offers an effective means to understand brittle deformation from micro to centimeter scales.

Characterization of two-phase flow in a faulted sandstone

Fault zones present in some underground CO2 storage formations can impact on injectivity, storage capacity, and the path taken by migrating CO2, including possible leakage to overlying formations and the escape of a plume beyond the area of a demarcated storage lease licence. A thorough understanding of the 2-phase flow in fault zones is therefore essential to de-risk any storage location where faults could be present. Many previous studies have addressed top-seal risks from fault reactivation, but the influence of intra-reservoir faults on flow within the target storage formations has received less attention. Studies of intraformational faults in sandstones have typically used plugs cored from outcrops or from subsurface boreholes, where important aspects of the geological history such as the stress conditions during faulting, and the degree of post-faulting compaction and cementation may be poorly constrained. Moreover, only intact fault rocks can be cored and re-loaded under stress with this approach, so that it is very difficult to establish the interacting effects or rock fractures and cataclastic gouge in a single experiment using borehole/outcrop samples.This study investigates newly created fault rock in sandstone that has been deformed under controlled conditions and without the effects of secondary cementation. We used a large direct shear rig to deform a large, water-saturated Bentheimer sandstone block to sufficient displacement (40mm) and under enough overburden pressure (25 MPa) to create a zone of cataclastic gouge several mm thick bounded by a damage zone of fractured rock. The sheared block was cored at an inclined angle while deep frozen to extract an oriented plug containing a complete and intact section of fault rock that could be reloaded under hydrostatic conditions in an x-ray transparent core holder. The faulted plug of Bentheimer was used for running steady-state drainage and imbibition 2-phase flow experiments. The fluid saturation and its spatial distribution in 3D inside the faulted plug were dynamically monitored during all stages of the experiment in a medical x-ray CT scanner.Analysis of the flow patterns revealed from the X-ray CT images collected over time enables us to characterize in detail, the influence of recently formed fault core and damage zones on fluid flow both during drainage as gas breaks across the fault zone, and as water re-invades during imbibition. The fault core acts as a semi-permeable membrane that is only permeable to the wetting phase (water) under pressure differentials less than the capillary entry pressure (Pce) of the membrane. During drainage stages, the high Pce of the fault core led to backfilling of the upstream end of the core and almost to compartmentalization of the sample. The fracture network that exists in the damage zone played a critical role in keeping the upstream side of the fault core connected to the downstream side. During imbibition stages, the high Pce of the fault core led to significant gas trapping at the upstream side of the fault core adjacent to the fault core-damage zone interface. While the fault core formed a barrier to flow, the fracture network can provide bypass pathways for gas flow. In this particular sample bypassing through fractures was sufficient such that for a particular value of average gas saturation the flow rate was faster in the faulted rock than in the unfaulted reservoir rock.

Experimental study of the features of filtration of non-Newtonian oils in a porous medium

The current state of development of deposits with high-viscosity oils is characterized by a low value of the achieved oil recovery with a high water cut in the produced wells. However, ways to improve the implemented development systems in order to increase the recovery factor in conditions of high water cut in well production, especially in the late stage of operation requires further research. Therefore, this research intended to investigate features of filtration of non-Newtonian oils in a porous medium. Oil fields with a complex geological structure have been discovered in many oil and gas regions of the world. These fields are characterized by a small oil-saturated thickness of the reservoirs, low reservoir properties, high viscosity of reservoir oil and heterogeneity of productive horizons. To study the filtration process, a specially designed installation was used. Clearly, the main elements are a column (core holder) with a water jacket, an oil tank, a thermostat and a high-pressure air tank (compressor). A research experiment was undertaken in two oil fields, which are X and Y. The results of physicochemical properties of oil field X showed that the density was 0.878g/cm3, followed by sulfur content (1.51%), pitches (21.89), asphaltenes was 4.19, and paraffin was 5.18.

Investigation and prediction of thermal cracking and permeability enhancement in ultra-low permeability rocks by in-situ thermal stimulation

Thermal cracking in rocks can cause a significant increase in permeability, which is of great significance for enhancing the oil recovery of ultra-low permeability reservoirs. To evaluate the potential for thermally-induced permeability enhancement in ultra-low permeability rocks, in-situ thermal stimulation (ITS) and pulse-decay gas permeability (PDP) real-time measurement of Chang 8 tight sandstone and Longmaxi shale cores were performed in a specially designed joint test system of the high-temperature pseudo-triaxial core holder and PDP real-time tester at different temperatures and simulated in-situ stresses. Stereo light microscope (SLM) observation and computerized tomography (CT) real-time scanning were applied to qualitatively and quantitatively characterize the dynamic variation in the thermal crack during the ITS, respectively. The experimental results show that above the threshold temperature of about 500 °C, thermal cracks were rapidly initiating, propagating, and forming a multi-scale fracture network in situ, thus leading to an improvement in permeability up to 11.23 and 29.82 times, respectively. By combining lithology and thermal analysis with reservoir physical property measurements in a multi-scale approach, the huge difference in thermal expansion coefficient (DTEC) between minerals caused by the quartz phase transition from α to β (QPT) at 573 °C is proved to be the most crucial mechanism for thermal cracking and permeability enhancement. To describe the intrinsic relationship between thermal crack and permeability with temperature-pressure during the ITS, a mathematical model based on thermoelasticity, fracture mechanics, and percolation theory was proposed. The QPT from α to β was further verified as the crucial mechanism by coupling the DTEC as a function of temperature into the mathematical model and obtaining better fitting results for experimentally measured permeability. Through experimental investigation and mathematical modeling, ITS is demonstrated as a less promising reservoir stimulation strategy for the economic and efficient development of tight oil and shale gas reservoirs.

FILTRATION OF HYDROCARBONS BY POROUS CORE IN THE FIELD OF ACOUSTIC OSCILLATIONS

Purpose. The task was to investigate the effect of acoustic oscillations on the filtration ofhydrocarbons by the core of a porous medium for different pressures. The paper present theresults of an experimental study of hydrocarbon filtration by a porous medium core in thepresence of acoustic oscillations with the frequency of 2,7 kHz. Porous sandstone cores with aheight of 18 mm and a diameter of 53 mm were studied. The core holder was filled with engineoil which contained a piezoelectric acoustic oscillator, the electrical signal to the emitter wasgenerated by a generator and amplifier. During the studied filtration, the core was located atthe bottom of the core holder, which was filled with liquid hydrocarbons, which were used asengine oil.The aim was to investigate the effect of acoustic oscillations on the filtration of hydrocarbonsin a porous medium. For this purpose, an experimental setup, amplifier and piezoelectricemitter of acoustic oscillations were made, sandstone cores were prepared, experiments wereperformed and the mass of the filtered liquid was estimated.Methodology. An experimental study of the effect of acoustic oscillations with a frequencyof 2.7 KHz on the filtration of hydrocarbons by a sandstone core for different pressures wasperformed in laboratory conditions. Amplified oscillations from the electronic generator wereapplied to the piezoelectric emitter located in the core holder, which was filled with motor oil,the pressure in the oil was changed using a reducer and manometers. The mass of core-filteredoil was measured by electronic scales.Originality. It has been established that acoustic oscillations effectively affect the filtrationof hydrocarbons in porous media and increase filtration by tens of percent.Findings and practical implications. Experiments have shown that acoustic oscillations ina porous medium filled with hydrocarbons increase the filtration of hydrocarbons. The use ofacoustic oscillations for processing around the filter space of wells will increase the flow rateof wells.Experiments have shown that in the presence of acoustic oscillation, the filtration of engineoil by the sandstone core increase by tens % relative to the amount of filtration in the absenceof acoustic oscillations.Relevance of the topic. Increasing the flow rate of wells is an important scientific andpractical task, its solution can be cleaning the filter zone from clogging and improving thefiltration of useful fluid Under the action of acoustic oscillations.Keywords: hydrocarbon filtration; porous medium; acoustic oscillations; well; around thefilter area; debit.

Three-Dimensional Acoustic Device for Testing the All-Directional Anisotropic Characteristics of Rock Samples

Many oil and gas fields, especially non-conventional shale and compacted sand reservoirs, have formation anisotropy. The acoustic anisotropy measurement of cores in these reservoirs can guide drilling, well logging, and exploitation. However, almost all core holders are designed for cylinder cores, which are not suitable for all-directional measurements. A three-dimensional measurement device was designed on the basis of the cross-hole sonic logging method. This device mainly consisted of two pairs of transducers, a signal generator, an oscillograph, an omnidirectional positioning system, and a computer control system. By adjusting the measurement latitude and longitude circle automatically, this device scanned spherical sample rocks and obtained full-wave waveforms in all directions. Experiments were performed taking granite from the Jiaodong Peninsula, China, as an example, and the arrival times and velocities of the longitudinal and shear waves were calculated based on the full-wave waveforms. Thereafter, anisotropic physical characterizations were carried out on the basis of these velocities. These data play an important role in guiding formation fracturing and analyzing the stability of borehole walls.

Multi-point resistivity measurement system for full-diameter long cores during fluid displacement.

Water injection is often used to improve oil and gas recovery in the late stage of oil and gas reservoir development. Studies show that this process leads to complex changes in reservoir resistivity and affects the evaluation of remaining oil and gas saturation in the reservoir. In this study, a multi-point resistivity measurement experimental system suitable for full-diameter rock samples during fluid displacement was designed to simulate and explore the distribution and variation of resistivity in the reservoir flooding process. In this regard, two columnar electrodes were installed on the end face of the core sample to serve as fluid injection and outflow channels. Moreover, five groups of nail-shaped electrodes arranged at equal intervals were embedded on the rubber sleeve of the core holder. The electrical bridge metering combined with seven electrodes was used to measure the resistivity and variation of six parts of the core sample during fluid displacement. A confining pressure was applied to the core sample to simulate the underground high-pressure environment and force the nail-shaped electrodes to cling to the sample to improve the accuracy of resistivity measurement. The simulated water flooding experiment was carried out with a sandstone sample from Tarim Oilfield in western China, and the distribution and variation of the sample's resistivity were recorded. The experimental results conform to the laws of rock physics and confirm the reliability of the experimental system. The experimental system provides a guideline for determining the resistivity variation and evaluating the remaining oil and gas saturation of water-flooded reservoirs.