Core Plugs Research Articles

Analysis of ZTE MRI application to sandstone and carbonate

AbstractMicrotomography (μCT) and nuclear magnetic resonance (NMR) have been used to characterize porous media for decades. Magnetic resonance imaging (MRI) enables direct visualization of pore architecture and many pulse sequences exist. In this work, we tested the MRI pulse sequence Zero Echo Time (ZTE) to study sandstone and carbonate for its ability to address short relaxation times. We aimed at resolving two fluid conduit scales, that is, pores and fractures. In this research, we study tighter porous systems than those previously reported using ZTE. Additionally, pore cluster analysis (PCA), combined with ZTE, can be used to analyze pore‐fracture connectivity of relatively large core plugs. We show that ZTE can resolve two‐scale pore systems simultaneously, that is, fractures and pores. By combining time‐domain NMR pore‐size analysis and PCA, we show that careful selection of resolution is necessary to understand transport in porous media.

Effect of Conformance Control Patterns and Size of the Slug of In Situ Supercritical CO2 Emulsion on Tertiary Oil Recovery by Supercritical CO2 Miscible Injection for Carbonate Reservoirs.

The reservoir heterogeneity is the major cause of poor volumetric sweep efficiency in sandstone and carbonate reservoirs. Displacing fluids (water, chemical solution, gas, and supercritical CO2 (sc-CO2)) flow toward the high permeable zone. A significant fraction of oil remains in the low permeable zone due to the permeability contrast. This study used in situ sc-CO2 emulsion as a conformance control agent to plug the high permeable zone and improve the low permeable zone’s volumetric sweep efficiency in carbonate formation. We investigated the effect of two types of conformance control patterns and the size of sc-CO2 emulsion on tertiary oil recovery performance by sc-CO2 miscible injection for carbonate reservoirs at reservoir conditions. The conformance control patterns are achieved using two different approaches. In the first approach, the low permeable zone was isolated, and the diverting gel system, a 0.4 pore volume slug, was injected into a high permeable zone. In the second approach, the simultaneous injection of the diverting gel system, a 0.2 pore volume slug, was done on both the low and high permeable zones. The first sc-CO2 injection was conducted as a tertiary oil recovery mode to recover the remaining oil after water flooding. The diverting gel system was injected after the first sc-CO2 flood for the conformance control. The second or post sc-CO2 injection was conducted after the diverting gel system injection. The diverting gel system used in this study consisted of a polymer and a surfactant. An in situ emulsion was generated when the injected diverting gel system interacts with the sc-CO2 in the core plug. Results obtained from dual-core core flooding experiments suggested that the in situ sc-CO2 emulsion was generated successfully in the formation based on the different pressure increases and observation of the dual-core core flooding experiments. The volumetric sweep efficiency and oil recovery in both conformance control patterns were improved. The production performances were also compared for both conformance control models before and after the diverting gel system injection. The conformance control model 2 (simultaneous injection of the diverting gel system into low and high permeability cores) has a better choice to be applied in field application due to high recovery with a small sc-CO2 emulsion easy operation in the field.

Novel green surfactant made from L-aspartic acid as enhancer of oil production from sandstone reservoirs: Wettability, IFT, microfluidic, and core flooding assessments

Surfactant flooding is a proven chemical Enhanced Oil Recovery (cEOR) method. Commonly/commercially available surfactants impose adverse impacts on the environment and even human health. Thus, finding green surfactants is of interest to petroleum engineers to implement cleaner EOR processes. In the current study, a novel surfactant, namely (S)-2-Dodecanamido-Aminobutanedioic acid was synthesized from L-Aspartic acid (an amino acid). After confirming its successful synthesis by FT-IR and 1H NMR spectrometry, its first petroleum engineering application was investigated. To do so, the effect of the surfactant on oil-water IFT, oil-sandstone rock contact angle and oil recovery from glass micromodel and sandstone core plugs was reviewed. In the presence of the surfactant, at different water salinities, oil-water IFT and the oil-wetting tendency of sandstone rock is decreased. At the surfactant's critical micelle concentration, minimum IFT is 9.8 mN/m, and minimum contact angle is 92.40°, which respectively are obtained in the salinities of 40,000 and 20,000 ppm. These two salinities were selected for oil recovery tests. Microfluidic evaluation visually showed that chemical fluids made from the surfactant compared to saline water flooding push more oil out of the micromodel, i.e., increase the volumetric sweep efficiency. Furthermore, four sandstone core plugs were subjected to water and surfactant flooding, respectively, to review the dominant mechanism of oil recovery by the surfactant. Surfactant EOR, with the mechanism of IFT reduction enhances oil recovery by 1.5%. However, considering both the IFT reduction and wettability alteration mechanisms, in the presence of 20,000 and 40,000 ppm salinities, 11.19 and 6.04% more oil volume is produced, respectively. Therefore, it is evident that wettability alteration is the prevailing mechanism for cEOR by the surfactant. In a sentence, the cEOR application of the amino-acid-based surfactant is confirmed.

Emerging applications of TiO2/SiO2/poly(acrylamide) nanocomposites within the engineered water EOR in carbonate reservoirs

In this study, TiO2/SiO2/poly(acrylamide) nanocomposites (NCs) as a newly-developed-nano enhanced oil recovery (EOR) agent is proposed using a simple, green and economic method from the extract of pomegranate seeds. The ultraviolet–visible spectroscopy (UV–Vis), X-ray diffraction (XRD), Fourier-transform infrared spectroscopy (FT-IR), scanning electron microscopy (FE-SEM), transmission electron microscopy (TEM) and energy-dispersive X-ray spectroscopy (EDS) are applied to analyze the characterization of NCs. Nano-smart solutions are prepared from the dispersion of NCs within the smart water at three different concentrations (500, 1000 and 1500 ppm). The used smart water solutions are formulated from mixing the single and binary systems of the monovalent and divalent salts (NaCl, KCl, MgCl2, CaCl2, Na2SO4, MgSO4, K2SO4 and CaSO4) at different concentrations of 2500, 5000 and 10,000 ppm within the distilled water. In order to identify the effect of the prepared NCs in smart EOR applications, the interfacial tension (IFT) of crude-oil/smart-water and crude-oil/smart-nanofluid systems is measured using the pendant drop technique, the wettability behavior of carbonate rock is studied using the contact angle (CA) measurement, and recovery efficiency is determined by preforming the coreflooding test for eight core plugs. According to the obtained experimental results of IFT and CA, KCl-5000, K2SO4-5000, CaSO4 + CaCl2 (5000 + 5000) and K2SO4+ CaCL2 (2500 + 2500) are selected as the optimal smart solutions. Furthermore, the performance of the selected smart water solutions is influenced by 65% in IFT reduction, 32% in wettability alteration and 10.5% in oil recovery when the prepared NCs is added to the solutions. Nano-OSS3-5000 smart-nanofluid developed from mixing 1500 ppm of TiO2/SiO2/poly(acrylamide) NCs with 5000 ppm of CaSO4 and CaCl2 ions demonstrated the highest performance in increasing oil recovery from 36.0 to 46.53% original oil in place (OOIP).

Proof-of-concept for a probe to measure pore water pressure in oil-water saturated porous rock

The identification of the Oil/Water Contact (OWC) in a hydrocarbon reservoir is crucial for the determination of its volume and it is also important for detailed petrophysical calculations. Estimation of the OWC requires the determination of the Free Water Level (FWL). Routine practice in the oil and gas industry involves drilling multiple discovery wells since the undulation of the rock layers confining the hydrocarbon reservoir does not generally enable a single discovery well to intercept the water phase. Well drilling is expensive and industry looks forward to approaches to reduce the number of wells required for estimation of the OWC. In this context, this paper presents the proof-of-concept for a probe to measure pore water pressure in oil-water saturated porous rock. This would allow predicting the depth of the FWL in hydrocarbon reservoirs even if the single discovery well does not go through the OWC. This probe could significantly improve the appraisal process and guide the drilling campaigns, saving time, money and reducing the environmental impact of hydrocarbon search. The probe prototype was validated at laboratory scale via measurements of water pressure in core plugs saturated with water and oil. Mock-up tests on sandstone core plugs have shown that the probe can successfully measure water pressure in samples saturated with water and oil as long as the water phase is continuous in the pore space. The paper has therefore provided a proof-of-concept for a technology that can now be moved to the next readiness level.

Relationships between the geomechanical parameters and Archie’s coefficients of fractured carbonate reservoirs: a new insight

ABSTRACT Despite holding a significant proportion of the known hydrocarbon reserves by the carbonates, enough studies have not been conducted to understand their geomechanical parameters and their predictability, especially in Iran. The present paper introduces a novel approach for obtaining geomechanical parameters of carbonate rocks through investigating the relationship between geomechanical parameters and Archie’s coefficients in one of the Iranian fractured carbonate reservoirs. The geomechanical parameters here included Young’s modulus, bulk modulus, and shear modulus, while Archie’s coefficients were the cementation factor and formation resistivity factor. For this purpose, 14 representative limestone core plugs were chosen and Archie’s coefficients were determined and the effect of increasing confining pressure on these parameters was investigated. Then, through numerical simulations using Particle Flow Code (PFC3D), the geomechanical parameters of the reservoir, including Young’s modulus (E), (dynamic and static), bulk and shear modulus, and Poisson’s ratio were obtained. The numerical results were verified by the laboratory tests and wireline logs’ data and showed a satisfying matching. Finally, the empirical relations between geomechanical parameters and Archie’s coefficients were determined for the target reservoir. According to the obtained results, the average correlation between Young’s modulus and both the cementation factor and formation resistivity factor was about 95%, which is a satisfying accuracy. As expected, shear modulus and bulk modulus had a stronger relationship with E being respectively about 99% and 98%. Moreover, lab-measured porosity and Young’s modulus had a correlation coefficient of about 95%. The obtained results of the present study provide new insights into the simultaneous evolution of the reservoir’s mechanical and petrophysical characteristics.

Core-scale modeling of surfactant-assisted spontaneous water imbibition in carbonates

This work numerically investigates surfactant effects on spontaneous water imbibition in oil-wet carbonates. An open boundary core-scale imbibition model with 9 × 9 × 10 gridblocks was used in UTCHEM to simulate carbonate core plug exposure to a vast water body. The simulation models were developed based on surfactant-assisted imbibition tests that were conducted in secondary and tertiary oil production modes using Amott cells at 75°C. Capillary and gravity forces were captured by history matching the experiments. Through history matching, the inputs for surfactant adsorption and diffusion, capillary pressure and relative permeability were calibrated. In tertiary mode, the surfactants-assisted imbibition process presents the performance in mixed-wet state rather than oil-wet state, which is governed by wettability alteration. A simulation model for surfactant-assisted imbibition in secondary mode was used to investigate the effects of various factors including interfacial tension (IFT) reduction, wettability alteration, adsorption, volume of surrounding water and capillary force. The simulation results suggest that surfactant-assisted water imbibition in secondary mode is gravity dominant, which is facilitated by both IFT reduction and wettability alteration caused by addition of proper surfactants. Different from water imbibition in water-wet core, it presents vertically dominant oil flow with a hemispherical oil-rich area and uneven remaining oil saturation. It is obvious that sufficient surfactant supply in vast water is required to make effective imbibition, in consideration of surfactant consumption and changes in concentration gradients. This core-scale modeling provides insights of surfactant-assisted imbibition in initially oil-wet carbonates and helps scale up the application in a cost-effective way.

Pore-Structural Characteristics of Tight Fractured-Vuggy Carbonates and Its Effects on the P- and S-Wave Velocity: A Micro-CT Study on Full-Diameter Cores

Pore structure has been widely observed to affect the seismic wave velocity of rocks. Although taking lab measurements on 1.0-inch core plugs is popular, it is not representative of the fractured-vuggy carbonates because many fractures and vugs are on a scale up to several hundred microns (and greater) and are spatially heterogeneous. To overcome this shortage, we carried out the lab measurements on full-diameter cores (about 6.5–7.5 cm in diameter). The micro-CT (micro computed tomography) scanning technique is used to characterize the pore space of the carbonates and image processing methods are applied to filter the noise and enhance the responses of the fractures so that the constructed pore spaces are reliable. The wave velocities of P- and S-waves are determined then and the effects of the pore structure on the velocity are analyzed. The results show that the proposed image processing method is effective in constructing and quantitatively characterizing the pore space of the full-diameter fractured-vuggy carbonates. The porosity of all the collected tight carbonate samples is less than 4%. Fractures and vugs are well-developed and the spatial distributions of them are heterogeneous causing, even the samples having similar porosity, the pore structure characteristics of the samples being significantly different. The pores and vugs mainly contribute to the porosity of the samples and the fractures contribute to the change in the wave velocities more than pores and vugs.

Derivation of a Petrophysical Model for Contact Angle Based on PURCELL’S Equation and CO2-Sandstone Brine System Calculation for Core flooding Wettability Preservation

In the petroleum industry, core flooding intended to study the relative permeability of the carbon dioxide–brine–rock system is carried out using predetermined wettability states where carbon dioxide saturated brine is injected to displace carbonated brine. This prevents mutual solubility and acidity generation to influence wettability during gas flooding stage. However, no one has yet found out if these systems retain their ambient wettability states despite the availability of relevant petrophysical models that are useful for developing suitable modes for contact angle calculation. The motivation of this study stems from this knowledge gap in issues related to wettability preservation in multiphase flow in porous media. In this paper, we have used published data on carbon dioxide–brine–rock systems to show that core plugs do retain their predetermined wettabilities. The basis for this inference is the calculation of a wettability dependent parameter and contact angle, using a derived petrophysical model based on Purcell’s original equation. In addition to acid gas systems, a similar approach has also been applied to an oil–water system, which generally retains its predetermined wettability. Trends in contact vs. water saturation for both systems are found to be similar, indicating wettability preservation during core flooding. Consequently, we have demonstrated for the first time, the feasibility of contact angle calculation using our derived equation.

Enhanced Oil Recovery in the Wolfcamp Shale by Carbon Dioxide or Nitrogen Injection: An Experimental Investigation

SummaryWe present a comprehensive investigation of gas injection for enhanced oil recovery (EOR) in organic-rich shale using 11 coreflooding experiments in sidewall core plugs from the Wolfcamp Shale, and three additional coreflooding experiments using Berea Sandstone. Our work studies the effect of pressure, minimum miscibility pressure (MMP), soak time, injection-gas composition, and rock-transport properties on oil-recovery factor. The injection gases were carbon dioxide (CO2) and nitrogen. The core plugs were resaturated with crude oil in the laboratory, and the experiments were performed at reservoir pressure and temperature using a design that closely replicates gas injection through a hydraulic fracture, minimizes convective flow, and exaggerates the fracture to the reservoir-rock ratio. We accomplished this by surrounding the Wolfcamp reservoir-rock matrix with glass beads. Computed-tomography (CT) scanning enabled the visualization of the compositional changes with time and space during the gas-injection experiments and gas chromatography provided the overall change in composition between the crude oil injected and the oil recovered.As gas surrounds the oil-saturated sample, a peripheral, slow-kinetics vaporization/condensation process is the main production mechanism. Gas flows preferentially through the proppant because of its high permeability, avoiding the formation and displacement of a miscible front along the rock matrix to mobilize the oil. Instead, the gas surrounding the reservoir-core sample vaporizes the light and intermediate components from the crude oil, making recovery a function of the fraction of oil that can be vaporized into the volume of gas in the fracture at the prevailing thermodynamic conditions. The mass transfer between the injected gas and the crude oil is sufficiently fast to result in significant oil production during the first 24 hours, but slow enough to cause the formation of a compositional gradient within the matrix that exists even 6 days after injection has started. The peripheral and the slow-kinetics aspects of the recovery mechanism are a consequence of the low fluid-transport capacity associated with the organic-rich shale that is saturated with liquid hydrocarbons.Our results show CO2 overperforms nitrogen as an EOR injection gas in organic-rich shale, and higher injection pressure leads to higher oil recovery, even beyond the MMP. The gas-injection scheme should allow enough time for the mass transfer to occur between the injected gas and the crude oil; we achieved this in the laboratory with a huff ’n’ puff scheme. Our results advance the understanding of gas injection for EOR in organic-rich shale in a laboratory scale, but additional work is required to rigorously scale up these observations to better design field applications.

Characterization and oil recovery enhancement by a polymeric nanogel combined with surfactant for sandstone reservoirs

The characterization and enhanced oil recovery mechanisms of a nanosized polymeric cross-linked gel are presented herein. A negatively charged nanogel was synthesized using a typical free radical suspension polymerization process by employing 2-acrylamido 2-methyl propane sulfonic acid monomer. The synthesized nanogel showed a narrow size distribution with one peak pointing to a predominant homogeneous droplet size. The charged nanogels were also able to adsorb at the oil–water interfaces to reduce interfacial tension and stabilize oil-in-water emulsions, which ultimately improved the recovered oil from hydrocarbon reservoirs. In addition, a fixed concentration of negatively charged surfactant (sodium dodecyl sulfate or SDS) was combined with different concentrations of the nanogel. The effect of the nanogels combined with surfactant on sandstone core plugs was examined by running a series of core flooding experiments using multiple flow patterns. The results show that combining nanogel and SDS was able to reduce the interfacial tension to a value of 6 Nm/m. The core flooding experiments suggest the ability of the nanogel, both alone and combined with SDS, to improve the oil recovery by a factor of 15% after initial seawater flooding.

A novel approach to solve the water saturation challenges in reservoirs under LoSal water injection

Enhancing hydrocarbon recovery is an ongoing practice in the petroleum industry. Multiple approaches are developed and proved their effectiveness in increasing reservoirs recovery. One of the recent approaches is the Low Salinity Water Injection which is known in the industry by “LoSal”. The determination of the optimum low salinity of the injected water and the mechanism behind its ability to enhance the hydrocarbon recovery are still the subjects of interest for many researchers and industry professionals. Despite the value of the LoSal water injection, it brings with it a considerable challenge to the future formation evaluation, namely the determination of the fluids’ saturation. The mixing of the low salinity injected water with the original high-salinity formation water creates variable water salinity across the reservoir. This is known in the industry by the “mixed-salinity” problem. The horizontal and the vertical heterogeneity of the permeability and porosity across the reservoir is the main factor that controls the “mixed-salinity” distribution in the injected volume. The challenge of calculating the fluids’ saturation exists for both the infill drilling wells and the monitoring wells. For the infill drilling wells, the saturation calculations require accurate formation water resistivity values, Rw, which became variable due to the mixed-salinity. For the monitoring wells, the fluids saturation calculations require accurate formation water sigma absorption, Σw, which also became variable for the same reason. The inability to determine the current Rw and Σw on foot-by-foot basis results in incorrect calculations of the water and hydrocarbon saturations. This creates an economic burden on the reservoir management. The existing methods to interpret the fluids saturation in mixed-salinity reservoirs face the challenges of accuracy, effect of borehole environment and high-data acquisitions cost. A forward modeling is developed to illustrate the problem and its impact on the reservoir decisions making process. A solution to the challenges is proposed, investigated, and proved both theoretically and in the laboratory. The proposed solution is based on lowering the LoSal water resistivity, prior to injection, to be equal to the original formation water resistivity without changing its low salinity. This is achieved by mixing the LoSal water with either acid or alkaline based on the reservoir condition. The acid or alkaline will reduce the resistivity of the LoSal water while keeping its low salinity unchanged. The determination of the required volume of the acid or the alkaline is calculated using the conductivity mixing law and the solution is tested on core plugs. The possible effects of the acid on the formation lithology, specially the clay content is discussed and proved to be negligible due to the very low acid volume required. This is also supported by previously published measurements.

Quantifying Oil-Recovery Mechanisms during Natural-Gas Huff ‘n’ Puff Experiments on Ultratight Core Plugs

Summary Despite promising natural gas huff ‘n’ puff (HnP) field-pilot results, the dominant oil-recovery mechanisms during this process are poorly understood. We conduct systematic natural-gas (C1 and a mixture of C1/C2 with the molar ratio of 70:30) HnP experiments on an ultratight core plug collected from the Montney tight-oil formation, under reservoir conditions (P = 137.9 bar and T = 50°C). We used a custom-designed visualization cell to experimentally evaluate mechanisms controlling gas transport into the plug during injection and soaking phases and oil recovery during the whole process. The tests also allow us to investigate effects of gas composition and initial differential pressure between injected gas and the plug (ΔPi = Pg−Po) on the gas-transport and oil-recovery mechanisms. Moreover, we performed a Péclet number, NPe, analysis to quantify the contribution of each transport mechanism during the soaking period. We found that advective-dominated transport is the mechanism responsible for the transport of gas into the plug at early times of the soaking period (NPe = 1.58 to 3.03). When the soaking progresses, NPe ranges from 0.26 to 0.62, indicating the dominance of molecular diffusion. The advective flow caused by ΔPi during gas injection and soaking leads to improved gas transport into the plug. Total system compressibility, oil swelling, and vaporization of oil components into the gas phase are the recovery mechanisms observed during gas injection and soaking, while gas expansion is the main mechanism during depressurization phase. Overall, gas expansion is the dominant mechanism, followed by total system compressibility, oil swelling, and vaporization. During the “puff” period, the expansion and flow of diffused gas drag the oil along its flowpaths, resulting in a significant flow of oil and gas observed on the surface of the plug. The enrichment of injected gas by 30-mol% C2 enhances the transport of gas into the plug and increases oil recovery compared to pure C1 cases.

Experiment on CO2-brine-rock interaction during CO2 injection and storage in gas reservoirs with aquifer

To understand the impact of CO2-brine-rock interaction on formation properties and the differences between gas zone and water zone, dynamic and static experiments were conducted under gas reservoir conditions to imitate the process of CO2 injection and storage in gas reservoirs with aquifer. In this work, core plugs, rock debris and brine are taken from DF gas field, a giant gas reservoir with aquifer in the South Sea of China. Meanwhile, scan electron microscope (SEM), energy dispersive spectrum (EDS), X-ray diffraction (XRD) and flame atomic absorption spectrometry (FAAS) were also applied to analyze the mechanism of property alterations of brine and rock minerals due to CO2-brine-rock interaction. Results show that CO2-brine-rock interaction occurs in both gas zone and water zone since water evaporates into gas stream and CO2 dissolves into brine to form carbonic acid. CO2-brine-rock interaction can cause rock minerals dissolution and to fall from the matrix to form free particles suspending in pore space filled with fluids and flow along with them. It generally triggers sharp reduction of formation permeability and leads to negative impact on CO2 injectivity and storage. And the formation damage in gas zone is severer than that in water zone. Meanwhile, CO2-brine-rock interaction in good-quality reservoir in water zone can improve porosity and permeability to further enhance CO2 injectivity and storage capacity. Thus, dry CO2 should be preferentially injected into aquifer with good formation properties to weaken negative effect to ensure CO2 successful injection and storage in gas reservoirs with aquifer. This work also provides a reference for designing technical scheme of CO2 injection and storage in gas reservoirs with aquifer.

Identification of Seepage Mechanisms for Natural Gas Huff-n-Puff and Flooding Processes in Hydrophilic Reservoirs With Low and Ultra-Low Permeabilities

Abstract Hydrocarbon gas flooding/Huff-n-Puff (HNP) can improve the oil recovery in the unconventional reservoirs. Here, the mechanisms accounting for fluid flow in the low-permeability and ultra-low permeability reservoirs were experimentally and theoretically investigated. Core plugs collected from a typical China oilfield were utilized for the experiments. Additionally, methane was used as the injection agent to conduct natural gas HNP/displacement experiments. The results indicated that the use of natural gas as an energy supplement agent and the HNP development method can effectively improve the recovery efficiency of the aforementioned two types of reservoirs. During the HNP process, the oil recovery is effectively enhanced mainly in the first round and second round. Meanwhile, during gas injection and HNP, natural gas can evidently weaken the extraction and reduce the precipitation of heavy components. However, the natural gas injection can establish an effective driving pressure system in low-permeability core plugs, and the interaction between natural gas and oil can change the mobility ratio. Furthermore, it aids in avoiding viscous fingering and premature breakthroughs. Moreover, the oil can be sandwiched between the interface of the gas and water phases to form a slip channel in a hydrophilic core sample, which can quickly produce oil. Finally, a numerical model was developed by considering the reservoir parameters of Changqing Oilfield, China. The oil recovery after eight rounds of CH4 HNP was 80% higher than that achieved via depletion development. Additionally, the oil recovery curves are especially similar in the previous three HNP rounds. These curves show obvious differences from the fourth round onwards, which indicates that the asphaltene deposition and CH4 diffusion slightly affect the oil recovery factor during the initial production period.

In Situ Wettability Investigation of Aging of Sandstone Surface in Alkane via X-ray Microtomography

Wettability of surfaces remains of paramount importance for understanding various natural and artificial colloidal and interfacial phenomena at various length and time scales. One of the problems discussed in this work is the wettability alteration of a three-phase system comprising high salinity brine as the aqueous phase, Doddington sandstone as porous rock, and decane as the nonaqueous phase liquid. The study utilizes the technique of in situ contact angle measurements of the several 2D projections of the identified 3D oil phase droplets from the 3D images of the saturated sandstone miniature core plugs obtained by X-ray microcomputed tomography (micro-CT). Earlier works that utilize in situ contact angles measurements were carried out for a single plane. The saturated rock samples were scanned at initial saturation conditions and after aging for 21 days. This study at ambient conditions reveals that it is possible to change the initially intermediate water-wet conditions of the sandstone rock surface to a weakly water wetting state on aging by alkanes using induced polarization at the interface. The study adds to the understanding of initial wettability conditions as well as the oil migration process of the paraffinic oil-bearing sandstone reservoirs. Further, it complements the knowledge of the wettability alteration of the rock surface due to chemisorption, usually done by nonrepresentative technique of silanization of rock surface in experimental investigations.

Application of a new bio-ASP for enhancement of oil recovery: Mechanism study and core displacement test

The evaluations of Alkaline-Biosurfactant-Biopolymer (ABsBp) flooding for enhancement of oil recovery applications were explored. A lipopeptide biosurfactant (surfactin) and a biopolymer (schizophyllan) in combination with alkali (Na2CO3) were experimentally investigated to evaluate the possibility for EOR studies using native Omani reservoir cores and Berea core plugs. The selected oil reservoir was high permeability (500–1000 mD) sandstone type, the reservoir temperature of 50 °C, and less than 80% water cut. The crude oil was also procured from the selected Omani reservoir, having 27.15 API. The interfacial tension (IFT) values of 0.02–0.1mN/m were observed at comparatively lower biosurfactant and alkali concentrations. The effect of other chemicals and biosurfactant on biopolymer was also studied on its viscosity at reservoir temperature, and no adverse effect was observed on biopolymer performance in the presence of alkali and biosurfactant. The injection of a 0.5 PV slug of 1.1% (w/v) Na2CO3, 20% (v/v) biosurfactant (400 ppm) and 20% (v/v) biopolymer (600 ppm), followed by 3 PV of biopolymer (600 ppm) drive showed 14% and 32% of additional oil recovery from reservoir cores and Berea cores respectively. This is the first report of Alkali-Biosurfactant-Biopolymer application using surfactin and schizophyllan, showing additional oil recovery from Omani reservoir cores and Berea sandstone cores.

Experimental evaluation of live oil oxidation together with its physical properties during air injection in a tight oil reservoir

In this paper, an integrated and pragmatic framework has been developed to experimentally determine the live oil oxidation with its physical properties and evaluate performance of air injection in a tight reservoir. In addition to continuously measuring interfacial tension, slim tube tests were performed to monitor and quantify miscibility between air and live oil collected from the Upper Triassic Yanchang Formation of the Chang 7 tight oil reservoir in the Ordos Basin, China. The displacement experiments showed that oil recovery factor of air injection is obviously higher than that of nitrogen injection in core plugs collected from the tight oil reservoir, while static and dynamic oxidation experiments were then conducted to identify the inherent oxidation mechanisms. The comparative core displacement experiments of live oil by air and nitrogen injection under reservoir temperature and pressure were carried out to evaluate the enhanced oil recovery (EOR) performance of air injection. It is found that heat released by the oxygen addition reaction under the formation conditions of 60.0 °C and 16.00 MPa leads to the bond scission reaction. The gas generated by the bond scission reaction forms a flue gas displacement front together with the remaining nitrogen contained in the air. Although miscibility cannot be achieved, air injection followed by the oxygen addition reaction and the bond scission reaction can reduce oil viscosity and thus increase its flowability. As for the commonly experimental studies with dead oils excluding porous media, the oxidation degree and the corresponding physical properties are normally overestimated since light components are limited in the dead oils and porous media constrain the corresponding oxidation.

Mechanical properties of organic-rich shales based on nanoindentation: A case study of deep shale gas reservoirs in Zigong area, Sichuan Basin

The deep shale gas in the Zigong area of the Sichuan Basin has a wide distribution and has good prospects for exploration, which has become an important replacement area for shale gas exploration and development. In this area, the burial depth of Longmaxi Formation Shale is generally >3500 m. One of the most challenging tasks in the development of this type of reservoir is the accurate prediction of the mechanical properties of organic-rich shale. The application of the mechanical properties of shale is important to the success in multiple aspects of drilling, hydraulic fracturing, and production. Methods such as unconfined/triaxial compression tests with the use of core plugs and logging data interpretation are commonly used to obtain mechanical properties. However, these methods have their own limitations. Thus, to address the difficulty in the measurement of the mechanical properties of shale, the advanced nanoindentation test is introduced and used. Nanoindentation is a technique based on a hard tip, which is pressed into the surface of a sample. The advantage of this test is the use of a sample with a small volume, such as drill cuttings or fragments, which are easily obtained during drilling. The mechanical properties at the nanoscale level, including the hardness, Young’s modulus, and fracture toughness, are measured in the nanoindentation. Moreover, this technique can be used to evaluate the creep behavior of shale. In this study, grid nanoindentation is used to investigate the mechanical properties of drill cutting samples from the Longmaxi Formation Shale in Zigong area, Sichuan Basin. Subsequently, these mechanical parameters are used to evaluate the heterogeneous properties of shale at the nanoscale level. The results can help in analyzing the correlation between rock mechanical properties and shale constituents. This suggests that the nanoindentation test is a useful approach of estimating the elastic and mechanical properties of shale in situations where conventional rock mechanics test data cannot be measured.

DIGITAL ROCK ANALYSIS: AN ALTERNATIVE METHOD TO PREDICT PETROPHYSICAL PROPERTIES, CASE STUDY FROM MISHRIF FORMATION

The digital core analysis of petrophysical properties replace the use of conventional core analysis by reducing the required time for investigation. Also, the ability to capture pore geometries and fluid behavior at the pore-scale improves the understanding of complex reservoir structures. In this work, 53 samples of 2D thin section petrographic images were used for analyses from the core plugs taken from the Buzurgan oil field. Each sample was impregnated with blue-dyed epoxy, thin sectioned and then was stained for discrimination of carbonate minerals. Each thin section has been described in detail and illustrated by photomicrographs. The studied samples include a variety of rock types. Packstone is the most common rock type observed followed by grainstone and packstone – wackestone. Floatstone and dolostone are noted rarely in the studied interval. However, the samples of thin section images are processed and digitized, utilizing MATLAB programming and image analysis software. The entire workflow of digital core analysis from image segmentation to petrophysical rock properties determination was performed. A focused has been made on determining effective and total porosity, absolute permeability, and irreducible water saturation. Absolute permeability is estimated with the Kozeny-Carman permeability correlation model and Timur-Coates permeability correlation model. Irreducible water saturation simply is derived from total and effective porosity. Also, some pore void characteristics, such as area and perimeter, were calculated. The results of Digital 2D image analysis have been compared to laboratory core measurements to investigate the reliability and restrictions of the digital image interpretation techniques.