Core Plugs Research Articles

Rate-Controlled Mercury Injection Experiments to Characterize Pore Space Geometry of Berea Sandstone

Interpretation of the relationship between heterogeneity and the flow in porous media is very important in increasing the recovery factor for an oil or gas reservoir. Capillarity for instance, controls fluids static distribution in a reservoir prior to production and remaining hydrocarbons after production commences. Therefore, capillary pressure data are used by petroleum engineers, geologists, and petrophysicists to evaluate production characteristics of petroleum accumulations. Conventional pressure-controlled mercury porosimetry produces an overall capillary pressure curve and pore throat size distribution data that provide little information about the porous medium structure and pore geometry. The present study provides information on three capillary pressure curves obtained from rate-controlled mercury injection porosimetry; one describes the larger pore spaces or pore bodies of a rock, another describes the smaller pores or pore throats that connect the larger pores, and a final curve which corresponds to the overall capillary pressure curve obtained from the conventional pressure-controlled mercury injection. An experimental constant-rate mercury injection apparatus was constructed that consists of a piston displacement pump, a computer controlled stepper motor drive and a core sample cell designed to minimize dead volume. The apparatus was placed in a glass chamber and subjected to an air bath to maintain a constant temperature of 27o C throughout the experiments. Then constant rate mercury injection experiments were performed on three Berea Sandstone core plugs. Results show that volume-controlled or rate-controlled porosimetry provides considerably more detailed data and information on heterogeneity and the statistical nature of pore space structure than the conventional pressure-controlled porosimetry as pressure fluctuations with time reveal menisci locations in pore bodies and pore throats. Moreover, pore size distributions based on volume-accessed pores and pore radii were obtained from the pressure versus saturation relationship.

Smartwater-Based Synergistic Technologies Offer Potential in Enhanced Oil Recovery

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 209360, “Smartwater-Based Synergistic Technologies: A Next-Recovery Frontier for Enhanced Oil Recovery,” by Subhash C. Ayirala, SPE, Abdulkareem M. Alsofi, SPE, and Zuhair A. Al-Yousef, SPE, Saudi Aramco, et al. The paper has not been peer reviewed. _ In the complete paper, the authors explore the synergistic effects of smartwater in polymerflooding, surfactant polymer (SP) flooding, carbonated waterflooding, and foam-assisted gas-injection processes. A suite of multiscale experimental data is analyzed to demonstrate and quantify the benefits of water-chemistry synergies in these enhanced oil recovery methods. Smartwater increased oil recoveries by 5–7% in addition to reducing polymer-concentration requirements by one-third in polymerflooding. Experimental Materials, Methods, and Procedures _ Materials Brines. High-salinity water (HSW) as well as two low-salinity smartwater brines, SW1 and SW2, were used. HSW had a salinity of 57,670 ppm total dissolved solids (TDS). The two smartwaters had roughly the same salinity but different individual ions. SW1 was represented by a 10-times dilution of HSW, while SW2 was of the same salinity but enriched with mainly sulfate ions. Crude Oil. Two crude oils were used. The crude oil used for polymerflooding oil-displacement experiments had a viscosity of 2.0 cp, while the crude oil with a viscosity of approximately 4.4 cp at reservoir temperature (90–100°C) is used for SP-flooding experiments. Both the crude oils had an asphaltene content of approximately 6.0 wt%. Polymer. A sulfonated polyacrylamide polymer having a sulfonation degree of 25 mol% and a molecular weight of 12 million Dalton was used. Polymer concentrations within the range of 1,000–2,000 ppm were chosen for polymerflooding and SP-flooding experiments. Surfactants. A betaine-type amphoteric surfactant was used for SP-flooding experiments. The gases used to generate the foam were nitrogen gas and carbon dioxide gas (CO2) with a purity of approximately 99.99 and 99.50%, respectively. Core Samples. Carbonate core plug samples were obtained from carbonate reservoirs. One sample was used to conduct the displacement experiment with polymerflooding, while six preserved plugs were used for evaluating SP-flooding synergy with smartwater. The ambient porosity ranged from 22.1 to 29.3%, and air permeability ranged from 123 to 1,978 md. A single plug was used for polymerflooding oil-displacement tests, while two-plug composite core samples were used for SP-flooding experiments.

Core cleaning and wettability restoration – selecting appropriate method

The core cleaning approaches aim to remove native crude oil, mud filtrates and evaporated salts which leads to strongly water-wet cores. In the standard core cleaning method, the solvent(s) injection continues until no more oil is observed in effluent. This is generally confirmed by visual examination, rather than by analyzing the composition of effluent, simply because it is expensive. In this work, we selected two preserved rock sections from an oil reservoir in North Sea. 1.5-inch diameter core plugs were cleaned by two different flush cleaning programs (so-called Program-1 and 2). In Program-1, samples were flushed first with 75% toluene + 25% methanol and then followed by alternate of toluene-chloroform-methanol until the samples were deemed cleaned from visual examination. In Program-2, samples were flushed by alternating toluene-tetrahydrofuran-chloroform for 8 cycles. Oil effluents from Program-2 were collected for composition GC analyses. The efficiencies of two flush cleaning programs were compared by measuring the wettability of the samples by combined Amott-USBM wettability method. The USBM index shows samples after cleaning program-2 are more water wet. Samples were then aged in crude oil at reservoir conditions for 4 weeks. Drainage and imbibition capillary pressure using centrifuge and porous plate and the end-point liquid permeabilities were then measured on restored samples. End-point properties after aging process, showed wettability being restored to intermediate water-wet as is expected from field production history. This study shows that standard cleaning does not fully clean these samples. Meanwhile, the elaborate Program-2 is often impractical, takes too long, is expensive and limited by laboratory capacity.

Dissolution behaviour in carbonate reservoirs during WAG injection: A preliminary experimental study

In this study, a core flooding experiment using a water-alternating-gas (WAG) injection was conducted to evaluate its impact on the petrophysical properties of an initially oil-saturated heterogeneous carbonate core sample. Carbon dioxide (CO2) and synthetic formation brine were injected (0.5 pore volume CO2 alternating with 0.5 pore volume brine) alternately following establishment of waterflooding residual oil saturation under reservoir conditions. Gas porosity, gas permeability, NMR (nuclear magnetic resonance) T2 measurements, and X-ray CT scanning were conducted preand post-core flooding. The results show that CO2-WAG injection resulted in substantial additional oil recovery (~30 %) under the applied experimental conditions. The results also show an increase in the permeability of the tested sample from 1.5 to 16 mD, which could be attributed to mineral dissolution. X-ray CT imaging shows signs of excessive mineral dissolution and formation of wormhole structures. It is believed that dissolution within the tested core plug caused the WAG fluids to follow the newly wormhole (causing them to enlarge further), and consequently bypassing many parts of the sample. Therefore, despite a significant increase in oil recovery, a large amount of oil is still left behind.

Normalize and De-Normalize of Relative Permeability Data for Mishrif Formation in WQ1: An Experimental Work

In many oil-recovery systems, relative permeabilities (kr) are essential flow factors that affect fluid dispersion and output from petroleum resources. Traditionally, taking rock samples from the reservoir and performing suitable laboratory studies is required to get these crucial reservoir properties. Despite the fact that kr is a function of fluid saturation, it is now well established that pore shape and distribution, absolute permeability, wettability, interfacial tension (IFT), and saturation history all influence kr values. These rock/fluid characteristics vary greatly from one reservoir region to the next, and it would be impossible to make kr measurements in all of them. The unsteady-state approach was used to calculate the relative permeability of five carbonate for core plugs from the Mishrif formation of WQ1. The relative permeability calculated by using Johnson, Bossler and Naumann (JBN) Correlation, which is, consider one of the unsteady-state approach where it found that the core plugs are water wet. A normalizing approach has been used to remove the effect of irreducible water and residual saturations, which would vary according on the environment. Based on their own irreducible water and trapped saturations, the relative permeabilities can subsequently be de-normalized and assigned to distinct sections (rock types) of the reservoir. The goal of this research is to normalize the relative permeability that was determined through water flooding.

Implications of static low-frequency model on seismic geomechanics inversion

I have developed a novel insight into the differences between static and dynamic moduli and their effects on the performance of seismic geomechanics inversion. This achievement is obtained from triaxial deformation tests and ultrasonic measurements on core plugs and reveals that the static Young’s modulus deviates from the dynamic one in porous media, especially in particular ranges of depth and pressure, although conventional regression relationships suggest the opposite, i.e., similar trends for the static and dynamic Young’s moduli. Next, a novel simple approach is formulated to incorporate laboratory information directly into a seismic low-frequency model (LFM) using an artificial neural network to achieve a static low-frequency model (SLFM). Respecting the critical role of the LFM in the reliability of seismic inversion, any modification to the process of building this model can contribute to higher accuracy of the subsequent seismic geomechanics modeling. For this, LFMs are built using static and dynamic data before proceeding to seismic inversion to derive 3D cubes of static Young’s and bulk moduli. The results are successfully validated using data from known wells as well as a blind well. The modeling outcomes demonstrate that the seismic inversion based on the dynamic low-frequency model (DLFM) would return the same results for static and dynamic bulk moduli. In contrast, the results are erroneous for the static Young’s modulus when the conventional DLFM was adopted. Accordingly, the intelligent approach to static low-frequency modeling is found to be a good interpolation technique for estimating geomechanical parameters, as indicated by the good agreement between the static data and the corresponding inversion results at the well locations. My findings place emphasis on the necessity of reconsidering the relationship between the static and dynamic Young’s moduli and highlight the advantage of using an SLFM to increase the accuracy of geomechanical modeling.

Impact of salt deposition induced by water evaporation on petrophysical properties and pore structure in underground gas storage through dynamic and static experiments

During the production process of underground gas storage (UGS) with high-salinity formation water, salt deposition has been observed due to formation water evaporation. This work aims at understanding the effect of salt deposition on petrophysical properties and pore structure. Firstly, dynamic and static experiments are carried out to simulate the multi-cycle gas injection and production of the UGS based on the core plugs, rock debris and water from Wen23 gas field. Secondly, Nuclear magnetic resonance (NMR), scan electron microscope (SEM) and energy dispersive spectrum (EDS) are applied to investigate the change of pore structure and salt-crystal morphology. Results indicate that the core permeability and porosity after water evaporation are averagely increased by 39 % to 68 % and 42 % to 66 % respectively compared with the initial water saturation conditions under different water salinity. Salt crystals in the reservoir are mainly deposited in large pores. The dispersed and aggregated salt crystals are observed and most salt crystals are between 1 μm and 5 μm in size. Thus, formation water evaporation is beneficial to the improvement of reservoir petrophysical properties without formation water supplement. This work provides an effective method to understand the impact of salt deposition caused by formation water evaporation on the petrophysical properties, fluid flow ability, and gas storage capacity of the UGS and CO2 geological storage.

Parameterization of core plug replacement properties for flexural performance optimization of repaired composite honeycomb sandwich panel

As lightweight structures, composite sandwich panels are distinguished by their significant flexural performances, which make them suitable for lightweight design applications, especially in the aerospace industry. These structures are very prone to different damages, which affects the structure’s performance. In this study, the numerical three-point bending test is carried out to evaluate the flexural performance of the damaged and repaired panel by comparing it with the intact panel values. The response surface methodology (RSM) is then adopted to analyze the core plug replacement properties’ effect on the flexural performances of the repaired honeycomb sandwich panel. Adequate models between the core plug replacement design parameters and the repaired panel flexural responses are built and discussed. In addition, aiming to determine the optimized core plug replacement parameters of the proposed repaired panel flexural performances, an optimization technique is implemented.

Petrofacies-Dependent Cementation Factor Relationship for Low-Resistivity Miocene Carbonates: Mumbai Offshore Basin

Summary In Mumbai offshore, Miocene carbonates are deposited with intermediate clastic inputs under cyclic sea level changes and have undergone diagenesis from time to time. Miocene carbonate layers deposited southwest of Mumbai High are producing a good amount of hydrocarbon from 1 to 2 Ω·m resistivity pays. A total of 58 representative core plugs from four different wells were studied to identify the reason for low resistivity and to classify rock facies types and porosity systems using scanning electron microscopy (SEM), thin-section nuclear magnetic resonance (NMR), and petrophysical core data. It was observed from the core study that Miocene carbonates have complex porosity systems and mud-supported to grain-supported reservoir facies. Dominance of mud-supported matrix is the main reason for low resistivity in Miocene carbonate layers as observed from integrated advanced log and core studies. Conventional petrophysical evaluation using constant petrophysical parameters (a, m, n) or linear correlation of cementation factor with porosity can lead to erroneous results in this scenario. A petrofacies-dependent correlation among cementation factor and porosity is attempted in this study for realistic evaluation of low-resistivity carbonate reservoirs. Different cementation factors vs. porosity relations have been derived for various carbonate formations worldwide. Shell formula demonstrates that cementation factor increases with decreasing porosity while correlation derived by Borai and Rafiee brought out inverse relation among cementation factors with porosity in tight carbonates and is providing almost constant cementation factor beyond 0.2. But, in our study, a core porosity-cementation factor plot of reservoir facies is showing that below 0.1, m values are increasing with increase of porosity, which is contradictory to Shell formula. This trend of cementation factor at low porosities is due to the presence of secondary porosity. In the porosity range 0.1–0.25, cementation factor increases eventually with the increase of porosity, but beyond porosity values 0.25, increase in porosity causes decrease of cementation factor. This is due to increasing content of mud-supported matrix, which is overall increasing the total porosity but eventually decreasing cementation in a rock. A new nonlinear correlation has been established between m and porosity for Miocene carbonates of Mumbai offshore area, by incorporating all the factors affecting cementation factor (m). Finally, saturation estimated using variable m either using newly established core derived correlation or resistivity image data is giving representative and improved saturation against low-resistivity reservoir layers compared with constant m.

Routine Core Analysis (RCAL) Untuk Menentukan Porositas, Permebilitas, dan Saturasi Pada Batupasir (Sandstone)

The physical properties of basic reservoir rocks that are very important to know, especially in the oil and gas industry, include porosity, permeability and saturation. The three physical properties determine the economics of an oil and gas field, especially in the reservoir rock layer. Sandstone (sand) is a lithology that very common oil and gas reservoir rock. The research was conducted at a laboratory scale using three (3) core plug samples from conventional cores. The method used in the Porosity measurement is Boyle's law helium porosimeter, while for the measurement of saturation using the results of the Conventional Retort method. The results of his research are the porosity values of the three samples taken from an average value of 23.76%, which is in the very good (very good) category. Meanwhile, the permeability values of the three samples were taken from an average value of 211.67 mD which is also in the very good category. From the graph of porosity to permeability it shows a directly proportional relationship, then from the graph of porosity to depth of the three samples above it shows an inverse relationship, those are shown by the trendline but with a very low R2 value. This is possibly caused by two things, namely: lack of sample data, and too close sample interval so that it cannot be used as justification that porosity and depth are not reversed. Oil saturation values (So) and gas saturation (Sg) of the three samples were taken from the average values of 46% and 1.7%.

Reservoir Characterization of Pila Spi Formation (Middle–Late Eocene) in Shaqlawa and Shekhan areas, Kurdistan Region, Northern Iraq

This study investigates reservoir quality for the Middle–Late Eocene Pila Spi Formation in Shaqlawa (Sarkand) and Gulley Keer (Shekhan) areas in Kurdistan Region of Iraq. Lithologically, the Pila Spi Formation in the studied sections is composed of limestone, dolomite, dolomitic limestone, chalky limestone, and marl. The thickness of the formation is about 102m and 200m in Sarkand and Gully Keer sections respectively. In order to evaluate the reservoir characterization of the studied formation, different techniques such as a microscopic study and core plug analysis were used. The Pila Spi Formation is characterized by several pore's types namely; vugs, moldics, channels, interparticles, fractures, boring, fenestral, and intragranulars. Several diagenetic processes were also recognized such as dolomitization, pressure solution, stylolization and dissolution. Based on the petrographic study, the lower part of the formation in Sarkand section has a porosity average of 8%, while it has an average of 21% and 17% in middle and upper parts. In Gulley Keer section, the porosity values of the formation are about 9%, 17, and 19%, in the lower, middle and upper part, respectively. The Scanning Electron Microscope (SEM) study shows almost the same porosity values, and the pore's sizes are between micropore to mesopore for the studied sections. Furthermore, the results of the core plugs analysis are roughly in agreement with optical assessments since the measured porosity values from Sarkand section are 8%, 18.5%, and 18% for lower, middle and upper parts, respectively. The porosity values of Gulley Keer section for lower, middle and upper parts of the studied section are 2.5%, 17.25%, and 22.5%, respectively. Consequently, the results revealed that the Pila Spi Formation has a good porosity except the lower part. In regards with permeability, the measured values of permeability displayed an avenge of 0.109md and 0.6698md for Sarkand and Gulley Keer respectively in which suggested fair to good permeability.

A Systematic Investigation of Polymer Influence on Core Scale Wettability Aided by Positron Emission Tomography Imaging.

Polymers have been used as viscosifying agents in enhanced oil recovery applications for decades, but their influence on rock surface wettability is rarely discussed relative to its importance: wettability largely controls fluid flow in porous media and changes in wettability may significantly influence subsequent system performance. This paper presents a two-part systematic investigation of wettability alteration during polymer injection into oil-wet limestone. The first part of the paper determines wettability and wetting stability on the core scale. The well-established Amott-Harvey method is used, and five full cycles performed with repeated spontaneous imbibition and forced displacements. Wettability alterations are measured in a polymer/oil system, to determine polymer influence on wettability, and evaluated towards simpler brine/oil and glycerol/oil systems, to determine reproducibility and uncertainty related to the method and fluid/rock system. Polymer injection into oil-wet limestone core plugs is shown to repeatedly and reproducibly reverse the core wettability towards water-wet. Wettability changed both quicker and towards stronger water-wet conditions with polymer solution as the aqueous phase compared to brine and glycerol. The second part of the paper attempts to explain the observed behavior; by utilizing in situ imaging by Positron Emission Tomography, an emerging imaging technology within the geosciences. High resolution imaging provides insight into fluid flow dynamics during water and polymer injections, identifying uneven displacement fronts and significant polymer adsorption.

New methods to evaluate impacts of osmotic pressure and surfactant on fracturing fluid loss and effect of contact angle on spontaneous imbibition data scaling in unconventional reservoirs

Osmotic pressure (Posmotic) is an important mechanism for fracturing fluid loss in clay-rich unconventional reservoirs. Surfactant is often added to the fracturing fluid to control this loss. While laboratory-based methods can be used to evaluate the impacts of Posmotic and surfactant on fracturing fluid loss, two important challenges exist in the commonly-used methods: 1) a pair of sister core plugs have to be used; and 2) the petrophysical properties of the sister core need to be very similar for meaningful comparisons, which may be impossible in many cases. In addition, for the scaling of laboratory spontaneous imbibition data, wettability (i.e., contact angle, θ) should be incorporated into the scaling model. However, θ is a scale-dependent parameter, e.g., macro- (θmacro), micro- (θmicro) and pore- (θpore) contact angles can vary significantly. It is currently uncertain which θ should be used in the scaling model.

Propagation of mineral dissolution waves driven by cation exchange in low salinity waterflooding

Low salinity waterflooding (LSWF) is an emerging improved/enhanced oil recovery (IOR/EOR) technique with an applicability in both sandstone and carbonate reservoirs. The underlying recovery mechanism of LSWF is still not completely understood due to the multiscale complex interactions occurring in crude oil/brine/rock (COBR) systems. There are several proposed mechanisms, where mineral dissolution is the most prominent among them. The objective of this paper is to study the brine-rock interactions, and understand the propagation of mineral dissolution waves in LSWF processes through theoretical analysis and geochemical modeling. A reactive transport geochemical modeling using PHREEQC (pH-REdox-EQuilibrium in C programing language) simulator has been carried out to understand the interplay of different geochemical effects such as multivalent cation exchange, and mineral dissolution during flow and transport in LSWF. The presence of clays and carbonate cements is most common in sandstone reservoirs, while some carbonate reservoirs also contain clay minerals. Therefore, a core scale geochemical model containing clay and carbonate minerals as active minerals for brine-rock interactions is chosen as a representative analog for most sandstone reservoirs and some of the carbonate reservoirs in this study. The results show that LSWF disturbs the geochemical equilibrium between the formation brine and reservoir rock minerals thereby causing the carbonate mineral dissolution. It is also inferred that without the cation exchange effect of clay minerals, carbonate mineral dissolution effects are local and they occur only close to the inlet of a core plug sample during LSWF. The new equilibrium between brine and rock minerals is then established rapidly. In the presence of clay minerals and cation exchange effect, the clay surfaces were found to preferentially adsorb divalent cations over monovalent cations during LSWF. Such cation exchange process softens the injected low salinity brine to maintain the brine under saturation with respect to carbonate minerals, and subsequently propagates carbonate mineral dissolution waves across the full length of the core sample. The novelty of this work is that it proposes and demonstrates a new geochemical based mechanism for LSWF, i.e., the propagation of mineral dissolution waves driven by the cation exchange process in the reservoir. The identified mechanism has several practical implications in the field: (1) carbonate mineral dissolution and the associated local pH increase can extend from local to reservoir scale, (2) the resulting mineral dissolution effectively releases the oil attached to the mineral surfaces, and (3) increasing the pH modifies the surface charges of both the rock and crude oil to be more negatively charged. The resultant electrostatic repulsion between the two interfaces would increase the water-wetness of rock surfaces to achieve higher improved oil recovery in LSWF.

Field gas huff-n-puff for enhancing oil recovery in Eagle Ford shales – Effect of reservoir rock and crude properties

• A unique experimental design for investigating oil extraction from shales by huff-n-puff process. • Utilization of field gas as a solvent for enhancing shale oil production. • Oil extraction efficiency could decrease with gas-oil ratio despite increasing rock porosity. • Oil viscosity strongly influences produced oil composition and recovery factor. Field gas huff-n-puff has a great potential for enhancing oil recovery in shale reservoirs that suffer from dramatic production decline. However, most previous studies have focused on CO 2 huff-n-puff, and a simplified injection hydrocarbon gas composition has been commonly used in nearly all experimental works. This work is a continuation of our previous study on the field gas huff-n-puff process for enhancing oil production from Eagle Ford shales with a focus on the impact of reservoir rock (porosity, permeability, and S 1 content) and crude oil properties (viscosity, density, composition). A unique huff-n-puff process was designed to investigate the characteristics of oil production during soaking and pressure depletion. The efficiency of oil extraction as well as the associated production mechanisms were evaluated based on the ultimate recovery factor and properties of produced oil. Huff-n-puff experiments were conducted on reservoir core plugs with distinct reservoir properties (i.e., porosity, permeability, and S 1 contents). It was found that an increase in Gas Research Institute (GRI) porosity from 4.3% to 12.9% could improve the oil recovery factor from 49.0% to 62.8%. However, such a trend was not observed in the huff-n-puff experiments with a higher OOIP where an increase of GRI porosity from 5.6% to 12% led to a decrease in recovery factor by 24.7%. This remarkable finding could be related to the decrease of gas-oil ratio as OOIP increased at a constant injected mass of gas. It was also found that the average URF decreased from 63.0% to 38.3% with an increase in oil viscosity from 3.56 to 9.59 cp, which could be attributed to the reduced diffusive mass transfer and phase partitioning of components from injection gas and resident oil. This work has advanced our understanding of how rock and oil properties affect oil the efficiency of oil extraction by cyclic gas injection in Eagle Ford shales. It also supports the development of reservoir screening criteria for a preliminary assessment of the suitability of an unconventional reservoir for this EOR method. Finally, the results present a unique high quality data set for further modelling work.

Predictive Soft Computing Methods for Building Digital Rock Models Verified by Positron Emission Tomography Experiments

AbstractThe influence of core‐scale heterogeneity on continuum‐scale flow and laboratory measurements are not well understood. To address this issue, we propose a fully automated workflow based on soft computing to characterize the heterogeneous flow properties of cores for predictive continuum‐scale models. While the proposed AI‐based workflow inherently has no trained knowledge of rock petrophysical properties, our results demonstrate that image features and morphological properties provide sufficient measures for petrophysical classification. Micro X‐ray computed tomography (μxCT) image features were extracted from full core plug images by using a Convolutional Neural Network and Minkowski functional measurements. The features were then classified into specific classes using Principal Component Analysis followed by K‐means clustering. Next, the petrophysical properties of each class were evaluated using pore‐scale simulations to substantiate that unique classes were identified. The μxCT image was then up‐scaled to a continuum‐scale grid based on the defined classes. Last, simulation results were evaluated against real‐time flooding data monitored by Positron Emission Tomography. Both homogeneous sandstone and heterogeneous carbonate were tested. Simulation and experimental saturation profiles compared well, demonstrating that the workflow provided high‐fidelity characterization. Overall, we provided a novel workflow to build digital rock models in a fully automated way to better understand the impacts of heterogeneity on flow.

Experimental Study on the Application of Cellulosic Biopolymer for Enhanced Oil Recovery in Carbonate Cores under Harsh Conditions.

Polymer flooding is used to improve the viscosity of an injectant, thereby decreasing the mobility ratio and improving oil displacement efficiency in the reservoir. Thanks to their environmentally benign nature, natural polymers are receiving prodigious attention for enhanced oil recovery. Herein, the rheology and oil displacement properties of okra mucilage were investigated for its enhanced oil recovery potential at a high temperature and high pressure (HTHP) in carbonate cores. The cellulosic polysaccharide used in the study is composed of okra mucilage extracted from okra (Abelmoschus esculentus) via a hot water extraction process. The morphological property of okra mucilage was characterized with Fourier transform infrared (FTIR), while the thermal stability was investigated using a thermogravimetric analyzer (TGA). The rheological property of the okra mucilage was investigated for seawater salinity and high-temperature conditions using a TA rheometer. Finally, an oil displacement experiment of the okra mucilage was conducted in a high-temperature, high-pressure core flooding equipment. The TGA analysis of the biopolymer reveals that the polymeric solution was stable over a wide range of temperatures. The FTIR results depict that the mucilage is composed of galactose and rhamnose constituents, which are essentially found in polysaccharides. The polymer exhibited pseudoplastic behavior at varying shear rates. The viscosity of okra mucilage was slightly reduced when aged in seawater salinity and at a high temperature. Nonetheless, the cellulosic polysaccharide exemplified sufficiently good viscosity under high-temperature and high-salinity (HTHS) conditions. Finally, the oil recovery results from the carbonate core plug reveal that the okra mucilage recorded a 12.7% incremental oil recovery over waterflooding. The mechanism of its better displacement efficiency is elucidated.

Separation of solid and liquid components in organic-rich chalks using NMR relaxation

Currently there is great interest in interpreting the 1H NMR T2 relaxation (i.e., transverse relaxation) of porous geological media containing both liquid-like and solid-like signals. This has an impact on the interpretation of commercial NMR core and log analysis of organic-rich shales, such as shale oil and shale gas, where T1-T2 relaxation maps are routinely used to identify sweet spots and producibility of the hydrocarbon reservoir. We report a novel method to separate liquid-like components with an exponential decay (T2e) in transverse magnetization from solid-like components with a Gaussian decay (T2G). The method uses novel pulse sequences together with a 20 MHz 1H NMR relaxometer optimized for reservoir core plugs. The method is applied to obtain 2D T1-T2 maps in organic-rich chalks saturated with water or heptane, as well as bitumen-extracted samples. The T1-T2 maps clearly distinguish liquid-like signals (including micro/meso-macro pore fluids, heptane dissolved in bitumen, and clay-bound water) from solid-like signals (including kerogen, bitumen, and clay hydroxyls) in the organic-rich chalks. The liquid-like (T2e) components in the T1-T2 maps show a clear contrast between water and heptane in the micro/meso-macro pores, which shows potential for improved fluid typing and saturation in organic-rich chalks and gives insights into diffusive coupling and bitumen blockage of the pore network. The solid-like (T2G) components in the T1-T2 maps are used for clay mineral identification, determination of kerogen content, and quantification of solvent-extracted bitumen versus bitumen expelled from kerogen due to swelling from dissolved heptane.

The influence of bioturbation on reservoir quality: Insights from the Columbus Basin, offshore Trinidad

Nine facies are recognised in two mid-Pliocene cores from the Columbus Basin, offshore east coast Trinidad. Facies successions are consistent with deposition within a deltaic-shoreface continuum. Lower shoreface deposits are heavily bioturbated by Scolicia, Asterosoma, Thalassinoides, Teichichnus, Palaeophycus and other elements of the Cruziana Ichnofacies whereas middle shoreface sandstone beds contain sand-filled burrows of the Skolithos Ichnofacies. Deltaic deposits record coarsening-upward successions with evidence of freshwater influx such as synaeresis cracks, fluid muds, and dispersed organic detritus. Prodelta and distal delta front deposits comprise heterolithic beds and contain sporadically distributed and diminutive structures belonging to the Phycosiphon Ichnofacies. Hummocky cross-stratification is prominent in storm-dominated proximal delta front sandstone deposits that are sparsely bioturbated by Ophiomorpha, Skolithos and other elements of the Rosselia Ichnofacies. Cryptic bioturbation is common at the top of these beds. Thin section examination, core plug analysis, and numerical modelling of the facies were undertaken to better understand fluid flow in bioturbated strata of the Columbus Basin. Whereas lithology and texture remain the primary control on reservoir quality, examples of biogenically enhanced permeability are present in the P3 and P7 cores. The highest permeability values are associated with highly bioturbated middle shoreface deposits that comprise clean, sand-filled burrows. Favourable permeability measurements are also attributed to cryptically bioturbated delta front sandstone beds. The latter display higher permeabilities when compared to unbioturbated and sparsely sandstone beds. Biogenic activity contributed to reduced permeabilities in lower shoreface and distal delta front deposits owing to extensive sediment packing and sediment mixing behaviours. Relationships between permeability and bioturbation intensity indicate that effective permeability in bioturbated intervals of the P3 and P7 cores are best characterised by the arithmetic mean of permeabilities and that simple statistical calculations can aid in the analysis of highly bioturbated facies (BI = 5–6).

Wettability alteration and reducing water blockage in tight gas sandstone reservoirs using mixed cationic Gemini/nonionic fluorosurfactant mixtures

AbstractThe unrecovered hydraulic fracturing fluid will invade the matrix and induce water blockage, creating formation damage and hindering the oil or gas production rate. First, the synergistic effect of cationic Gemini surfactant (MQAS) and nonionic fluorosurfactant (N‐2821) mixtures on reducing the surface tension and wettability alteration was investigated in this paper. The critical micelle concentration (CMC) of the surfactant mixture is one or two orders of magnitude lower than that of N‐2821 and MQAS, indicating that the MQAS/N‐2821 mixtures exhibit an apparent synergistic effect in reducing surface tension. Moreover, the maximal contact angle of MQAS/N‐2821 mixtures reached 83.55° at αN‐2821 = 0.5, and the total surfactant concentration of 1 × 10−4 mol/L due to the adsorption of surfactant. The adsorption mechanism of surfactants on the surface of quartz sand was then examined. The adsorption kinetics is consistent with the pseudo‐second‐order model at different surfactant concentrations, while the Freundlich model is suitable for describing the adsorption behavior of surfactants on the sandstone surface. This finding indicates that surfactant adsorption is multilayered. The MQAS/N‐2821 surfactant mixtures have excellent surfactant activity due to the relationship of the capillary pressure to the surface tension, pore radius, and contact angle; thus, the addition of surfactant mixtures can reduce the liquid saturation effectively. Furthermore, the sequential imbibition experiments indicate that MQAS/N‐2821 mixtures alter the wettability of the core plug, which results from the adsorption of surfactants. Compared with brine water, the MQAS/N‐2821 mixtures decreased the liquid saturation and increased the permeability recovery ratios of the core plug.