Water-saturated Core Research Articles

Investigating the effects of make-up water dilution and oil presence on polymer retention in carbonate reservoirs.

The application of polymer flooding is challenging in harsh temperature and salinity conditions in Middle-Eastern carbonate reservoirs, as they can deteriorate the commonly used polymers such as Hydrolyzed Polyacrylamide (HPAM). One solution to this issue is the use of newly developed Acrylamido-Tertiary-Butyl Sulfonate (ATBS) based polymers, which can endure adverse temperature and salinity conditions. However, they also tend to adsorb onto carbonate rocks with positive surface charge. This study aims to tackle the problem of high polymer retention by employing low-salinity polymer flooding. For that coreflooding experiments were conducted on an ATBS-based polymer in salinities ranging from 400 to 167,000 ppm using fully water-saturated cores and cores at residual oil saturation (Sor). The single-phase retention experiments determined polymer retention values of around 25µg/g-rock when using diluted brines, which is about half of the retention values (47-56µg/g-rock) observed with high salinity seawater (43,000 ppm) and formation water (167,000 ppm). Furthermore, the retention of the ATBS-based polymer was further reduced by 50% in the presence of oil compared to the experiments conducted in the absence of oil. The results demonstrated that an optimal salinity threshold of 10,000 ppm and lower yields significant improvements in the efficiency of polymer flooding.

Numerical modelling of CO2-in-water emulsion injection into a water-saturated core

Depressurization method shows promise for methane hydrate (MH) reservoir production, but the reformation of hydrates due to a lack of geothermal heat presents a significant challenge for commercial production. This study proposes a novel approach for MH gas recovery by injecting a CO2-in-water (C/W) emulsion into an MH reservoir aquifer. The exothermic nature of CO2 hydrate formation and liquid CO2 dissolution in water in this method provides heat to the MH layer, effectively preventing hydrate reformation. Subsequently, 1-D numerical models were developed and implemented using the MATLAB Reservoir Simulation Toolbox (MRST). These models were rigorously validated against experimental data under homogeneous conditions and varying injection schemes. The investigation indicated that the average volume fraction of CO2 hydrate within the hydrate particles was found to be 55% of the volume of liquid CO2 droplets. The alternating C/W emulsion injection increased the driving force for CO2 dissolution in water, thereby promoting subsequent hydrate particle decomposition and CO2 hydrate dissolution in water, which effectively mitigated blockage within the porous medium. In conclusion, water alternating C/W emulsion injection, along with the continuous injection of a low volume fraction of liquid CO2 within the C/W emulsion, exhibits promising potential for sustained injection and provides adequate heat to the MH layer, preventing hydrate reformation. Furthermore, the developed numerical model reasonably predicts the behavior of various injection schemes. This developed model can be used for devising long term sub-seabed carbon capture and storage development plan.

Investigation on the impact of CO2-Induced precipitation on microscopic pore structure of low-permeable reservoirs

CO2 injection into reservoirs might induce organic or inorganic precipitation in microscopic pores, and some of the pores are blocked by the precipitates, resulting in a decrease in the connectivity of pores and affecting oil recovery. In this paper, a set of experiments on CO2 displacement and CO2-water-oil-rock interaction are conducted to study the microscopic mechanisms of reservoir damage. In-situ Nuclear Magnetic Resonance (NMR) technology is applied to conduct the microscopic analysis of CO2-EOR and reservoir damage at real reservoir conditions. The results reveal that the particle size and the amount of inorganic precipitates formed in the formation water will increase with the rise of CO2 injection pressure, and the inorganic precipitates primarily consist of siderite and kaolinite. The change of NMR T2 spectra of the core samples reveals that the inorganic precipitates primarily block the small pores less than 0.89 μm. However, as a result of stronger mineral dissolution and solute transport, the pore volume of the large pores (greater than 0.89 μm) increases after the CO2-water-rock reaction. Ultimately, this interaction results in a 5.4% increment in pore volume. In addition, the displacement efficiency of water-saturated cores is improved after the first CO2 displacement, which indicates that CO2-water-rock interaction can effectively improve the seepage properties of reservoirs. Nevertheless, the reservoir damage caused by asphaltene precipitation during CO2 flooding is more significant. The asphaltene precipitation percentage in formation oil increases with the rise of CO2 injection pressure, reservoir temperature, and asphaltene content in virgin oil. CO2-induced asphaltene precipitation causes more severe blockage on small pores in comparison with large pores. After 2 h of CO2 injection to the oil-saturated core, permeability and oil recovery caused by CO2-induced precipitation decreased by 17.6% and 11.4%, respectively.

Fast permeability estimation using NMR well logging data log-normal decomposition

Nuclear magnetic resonance (NMR) well logging and NMR core analysis provide a non-invasive approach to a fast reservoir rock pore structures evaluation. The NMR data is presented as a time distribution called transverse relaxation time spectrum (T2 spectrum) and, with proper adjustment, the area under the T2 distribution curve is directly related to the porosity of the reservoir rock. Based on the assumption that immovable and free fluid are present in pores of different sizes, NMR well logging and core analysis use these differences to characterize the fluids found inside the rock pores. In this way, a fixed T2 value can be selected as a cutoff. The amplitudes of the T2 spectrum that have their T2 coordinates below this fixed value are related to the fluids that are in the small pores (immovable fluids), and those that have their T2 coordinates above this value are related to the large pores (free or movable fluids). This T2 value is called T2cutoff and can be estimated in a laboratory with NMR data acquisition on water-saturated core samples. This is done by comparing the NMR acquisition data from a plug fully saturated with water with the NMR acquisition data taken from the same partially saturated plug. In this work, a new method to estimate the pore size distribution, a variable T2cutoff curve, and the Timur–Coates permeability curve of the formation along the reservoir rock is presented. The method is based on the decomposition in log-normal components of the T2 spectra of NMR well logging and on the permeability and porosity of plugs, measured in a laboratory.

Multifractal estimation of NMR T2 cut-off value in low-permeability rocks considering spectrum kurtosis: SMOTE-based oversampling integrated with machine learning

The transverse relaxation time (T2) cut-off value plays a crucial role in nuclear magnetic resonance for identifying movable and immovable boundaries, evaluating permeability, and determining fluid saturation in petrophysical characterization of petroleum reservoirs. This study focuses on the systematic analysis of T2 spectra and T2 cut-off values in low-permeability reservoir rocks. Analysis of 36 low-permeability cores revealed a wide distribution of T2 cut-off values, ranging from 7 to 50 ms. Additionally, the T2 spectra exhibited multimodal characteristics, predominantly displaying unimodal and bimodal morphologies, with a few trimodal morphologies, which are inherently influenced by different pore types. Fractal characteristics of pore structure in fully water-saturated cores were captured through the T2 spectra, which were calculated using generalized fractal and multifractal theories. To augment the limited dataset of 36 cores, the synthetic minority oversampling technique was employed. Models for evaluating the T2 cut-off value were separately developed based on the classified T2 spectra, considering the number of peaks, and utilizing generalized fractal dimensions at the weight <0 and the singular intensity range. The underlying mechanism is that the singular intensity and generalized fractal dimensions at the weight <0 can detect the T2 spectral shift. However, the T2 spectral shift has negligible effects on multifractal spectrum function difference and generalized fractal dimensions at the weight >0. The primary objective of this work is to gain insights into the relationship between the kurtosis of the T2 spectrum and pore types, as well as to predict the T2 cut-off value of low-permeability rocks using machine learning and data augmentation techniques.

Modelling and validation of dry and saturated velocities in carbonates from Saudi Arabia – Part II

Ultrasonic compressional (P-wave) and shear (S-wave) velocity data, obtained from a set of 35 dry and water-saturated (carbonate) core samples, were presented as a first part to this study, in a separate paper by Bakhorji and Schmitt (2022). These carbonate samples were obtained from a prominent reservoir in Saudi Arabia.In this follow-up paper, the velocity measurements, obtained from these 35 core samples, were utilized to, firstly, predict and validate four appropriate rock physics models and to, secondly, derive empirical relationships relating the P- and S-wave velocities to the porosity and calcite content of the samples (over the effective pressure range from 5 MPa to 25 MPa). The derived empirical relationships were validated against the wireline P- and S-wave velocities assuming insitu reservoir pressure conditions. The empirical models predicted the P- and S-wave velocities accurately over the reservoir interval of interest. The shear strengthening / weakening effect, or the saturation effect on the shear moduli, was also modelled and is discussed further.The comparisons of the Biot, Gassmann, Mavko-Jizba-Biot (MJ-Biot) and Mavko-Jizba-Gassmann (MJ-Gassmann) model predictions, with the measured water-saturated P- and S-wave velocities, show that the squirt mechanism was not applicable for our samples. The Gassmann model consistently over-predicts the water-saturated S-wave velocities at low pressure, but closely fits the measured velocities at high pressures, whereas Biot over-predicts the water-saturated velocities in most of the studied samples. We conclude that Biot global-flow is most likely to be the principle dispersion mechanism in these samples.

Surface-Modified Graphite Nanoplatelets to Limit Deteriorative Impacts of Oil-Based Mud Residuals on Cement Bonding

Summary Successful cementing relies on the effective removal of oil-based muds (OBMs), especially from rock and casing surfaces. However, most OBMs are heavily absorbed onto the mineral surfaces as well as casing, deteriorating the interfacial bonding of cement to these surfaces. We present a novel cement additive using graphite nanoplatelets (GNPs) to minimize the impact of mud residuals on the bonding strengths of cement. To benefit from the individual superior mechanical properties of GNPs, we develop surface modification techniques to modify their surface properties and make them compatible with the aqueous medium of cement. Surface treatment of GNPs is critical to provide a uniform dispersion of them within the cementitious matrix and also create a strong interfacial bonding between them and cement hydrates. A series of push-out tests are conducted to evaluate how the addition of surface-modified GNPs affects the bonding strength at the cement/rock interfaces corresponding to different scenarios of OBM residues. The effect of different kinds of rocks, including sandstone, limestone, and shale, is also incorporated in the push-out tests. The experimental results show that after spacer flushing for the cases of limestone and sandstone cores, treated GNPs not only limit the impact of mud residuals at the interfaces but also raise the bonding strength beyond that corresponding to water saturated cores by about 357% and 194%, respectively. For the case of shale after spacer flushing, the bonding strength recovers about 70% as compared to the water saturated cores, and this strength is about 429% higher than that measured for the water saturated case when cement is plain (without surface-modified GNPs).

Investigation of the Selectivity of the Water Shutoff Technology

High water-cut oil production is one of the major issues in the petroleum industry. The present study investigates different profile control solutions, with an emphasis on selective methods and materials that mostly decrease the permeability of water-saturated reservoir areas. To achieve the selective water flow blockage in fractured porous media, the sodium silicate-based gel-forming composition was developed. The test procedure was created to assess selective and strength characteristics of the presented composition. According to the results of this procedure, adding polyatomic alcohols to the mentioned composition enhances its hydrophilic behavior in water-saturated rocks (work of adhesion increases from 117 to 129 mJ/m2) and reduces the hydrophobic behavior in oil-saturated rocks (work of adhesion drops from 110.3 to 77.4 mJ/m2). The selectivity of the composition performance is validated by its higher wettability of water-saturated reservoir rocks compared with oil-saturated; thus, the composition creates a more stable water shutoff barrier when entering the water zone in a formation. As a result of core flooding experiments in natural, fractured, porous core samples, the efficiency of the water blocking capacity of the composition was proved. In addition, these tests showed the selectivity of the composition because the permeability decrease in water-saturated core samples was higher than in oil-saturated ones. The experimental value of the selectivity coefficient was 152.14.

Experimental Study on Water-Plugging Performance of Silicon Dioxide/Polystyrene Hydrophobic Insoluble Microsphere Particle Flooded by High-Water-Cut Oil–Water Mixture

Abstract Water plugging was an important but difficult process close to high-water-cut production wells. The injected water-plugging materials were usually liquid and typically had been evaluated by conventional water-flooding experiments. In this study, silicon dioxide (SiO2)/polystyrene hydrophobic insoluble microsphere particles were introduced as a selective water shutoff agent, and the water-saturated core was flooded with a high-water-cut oil–water mixture. Indexes such as modified oil-coning time, water-cut fluctuation, and cumulative water cut were proposed to evaluate water-plugging capability. A parametric study was conducted to evaluate the influence of particle composition (A, SiO2/polystyrene particle; B, complete polystyrene particle), water cut of the injected oil–water mixture, and preheating temperature of the insoluble particles on water-plugging performance. The results from the index analysis and relative permeability curve showed that the proposed indexes could be used to compare water-plugging performance during oil–water mixture drive; both particles had better water-plugging performance when the injected mixture was not an ultrahigh water cut (fw &amp;lt; 90%). Particle B had larger lipophilicity and stronger capacity for decreasing the water cut (about 0.55–1.28%) at a conventional temperature when the oil–water mixture of the injected fluid had a water cut of 90%. Particle A had lower capacity to decrease the water cut (by about −0.94–0.26%), but it was resistant to reservoir temperature because of its dense structure and the addition of SiO2. These results provided suggestions for the application of hydrophobic insoluble microsphere particles in water plugging in production wells.

Competitive adsorption between CO2 and CH4 in tight sandstone and its influence on CO2-injection enhanced gas recovery (EGR)

CO2 flooding is a new promising way of achieving enhanced natural gas recovery (EGR) and CO2 sequestration in tight gas reservoirs. CO2 adsorption is a reality that cannot be ignored during CO2 flooding process. However, the adsorption behavior of CO2 in tight cores remains unclear. Here, the CO2CH4 competitive adsorption characteristics in tight sandstone were experimentally investigated. The results indicate that the CO2 show significantly higher adsorption capacity in the tight cores compared to CH4 and that competitive adsorption occurs after CO2 is injected into tight core preadsorbed with CH4, with over 30% of the CH4 being replaced by the injected CO2 under an ambient pressure of 24 MPa. Further, the results of sensitivity experiments demonstrated that CO2CH4 competitive adsorption is more significant in tight cores with lower permeability, higher rock fragment content, and lower water saturation, while experiments on CO2-EGR and CO2 storage showed that for tight cores with lower permeability or higher rock fragment content, the higher degree of competitive adsorption resulted in greater EGR efficiency and CO2 storage capacity. For water saturated cores, however, the dissolution of CO2 in water has a greater impact on EGR and CO2 storage compared to competitive adsorption, resulting in better EGR and CO2 sequestration efficiency at higher water saturation.

A novel computational method for determination of water saturation in oil reservoirs using discrete wavelet transform and nuclear magnetic resonance (NMR) T2 log

Nuclear magnetic resonance (NMR) technique is the most innovative tool to determine water saturation. Notwithstanding a solid foundation in theory, current NMR methods have some practical limitations to determine water saturation. The main problem with using the current method is to measure the cut-off value of transverse relaxation time from a large number of water-saturated core samples. Determining the cut-off value in the core laboratory is costly and time-consuming. Hence, this study is aimed at providing a new method for determining water saturation using wavelet transform and the transverse relaxation time log. In this study, the transverse relaxation time log was first decomposed repeatedly by wavelet transform to eliminate the porosity effect, thus achieving immovable fluid relaxation time. Then, water saturation was calculated at each depth using the current NMR method with different cut-off values, referred to as bound water saturation. Finally, by establishing a relation between bound water saturation and immovable fluid relaxation time, water saturation was calculated at each depth, referred to as irreducible water saturation. The results achieved from this study demonstrated that irreducible water saturation closely matches bound water saturation in various oil reservoirs. • Extracting immovable fluid relaxation ( T F ) time from transverse relaxation time ( T 2 ) • Establishing a relation between T F and water saturation. • Calculating water saturation based on the proposed equation.

Quantifying the Effect of Multiphase Flow on Matrix Acidizing in Oil-Bearing Carbonate Formations

Summary It is common to inject acidic stimulation fluids into oil-bearing carbonate formations to enhance well productivity. This process of matrix acidizing is designed to maximize the propagation of wormholes into the formation by optimizing the injection parameters, including acid-injection rate and volume. Previous studies have suggested that saturation conditions, permeability, heterogeneity, temperature, and pressure can significantly affect the design of matrix-acidizing treatments. However, laboratory studies’ results are inconsistent in their conclusions and are mostly limited to water-saturated cores. In this work, we designed a systematic experimental study to evaluate the impact of multiphase flow on the acidizing process when injecting 15 wt% hydrochloric acid (HCl) into crude-oil-saturated Indiana Limestone cores. The results reveal the following: Contrary to published literature for water-saturated cores, acidizing in partially oil-saturated high-permeability cores at high pressure requires less acid volume than in low-permeability cores; lower-pressure acid injection results in more efficient wormhole propagation in low-permeability cores compared to high-pressure acid injection; acidizing in low- and high-permeability cores at low pressure leads to similar efficiency; and wormholing is more effective in partially oil-saturated cores, resulting in multiple parallel branches as compared to inefficient leakoff in water-saturated cores.

Extreme capillary heterogeneities and in situ fluid compartmentalization due to clusters of deformation bands in sandstones

Previous work has shown that individual deformation bands act like capillary barriers and influence fluid saturation. More common in nature, however, are clusters of deformation bands that form complex three dimensional geometries. The aim of this study is to analyze the extent and mechanisms of fluid compartmentalization due to clustered bands. Drainage multiphase fluid flow experiments were performed on a Navajo sandstone core sample characterized by diversely oriented clusters of deformation bands, that sub-divide the host rock into several compartments. Medical X-ray CT images were acquired while nitrogen was injected at progressively higher flow rates into a water-saturated core during transient and steady-state conditions. Spatial and temporal analyses of the non-wetting phase plume migration suggest that deformation bands act like capillary barriers and contribute to the development of an extremely tortuous saturation front. Differential pressure behavior across the core is linked to the breakthrough of N2 into the individual compartments, resulting in highly variable N2 saturation throughout the experiment. Migration into downstream compartments occurs via the exceedance of capillary entry pressure in portions of the bands. Simulation models of simplified systems demonstrate that capillary end effects and discontinuities in the deformation bands impact fluid saturation. The experiments and models presented here show that clusters of deformation bands have the potential to strongly compartmentalize a sandstone reservoir. Hence, prior analysis of the geometry of deformation band structures in a reservoir could significantly reduce the risk of overestimating reservoir capacity, and improve predictions of fluid mobility.

A Three-Phase Study on Preflush Stage in Sandstone Acidizing: Experimental and Modeling Analysis of Evolved Carbon Dioxide in a Hydrocarbon and Aqueous Environment

SummaryLimited studies have been conducted in understanding the mechanics of preflush stages in sandstone-acidizing processes. Among those conducted in this area, all efforts have been directed toward singular aqueous-phase scenarios. Encountering 100% water saturation (Sw) in the near-wellbore region is seldom the case because hydrocarbons at residual or higher saturations can exist. Carbonate-mineral dissolution, being the primary objective of the preflush stage, results in carbon dioxide (CO2) evolution. This can lead to a multiphase presence depending on the conditions in the porous medium, and this factor has been unaccounted for in previous studies under the assumption that all the evolved CO2 is dissolved in the surrounding solutions. The performance of a preflush stage changes in the presence of multiphase environments in the porous media.A detailed study is presented on the effects of evolved CO2 caused by carbonate-mineral dissolution, and its ensuing activity during the preflush stages in matrix acidizing of sandstone reservoirs. Four Carbon Tan Sandstone cores were used toward the purpose of this study, of which two were fully water saturated and the remaining two were brought to initial water saturation (Swi) and residual oil saturation to waterfloods (Sorw) before conducting preflush-stage experiments. The preflush-stage fluid, 15 wt% hydrochloric acid (HCl), was injected in the concerning cores while maintaining initial pore pressures of 1,200 psi and constant temperatures of 150°F.A three-phase-flow numerical-simulation model coupled with chemical-reaction and structure-property modeling features is used to validate the conducted preflush-stage coreflood experiments. Initially, the cores are scanned using computed tomography (CT) to accurately characterize the initial porosity distributions across the cores. The carbonate minerals present in the cores, namely calcite and dolomite, are quantified experimentally using X-ray diffraction (XRD). These measured porosity distributions and mineral concentrations are populated across the core-representative models. The coreflood effluents' calcium chloride and magnesium chloride, which are acid/carbonate-mineral-reaction products, as well as spent-HCl concentrations were measured. The pressure drop across the cores was logged during the tests. These parameters from all the conducted coreflood tests were used for history matching using the numerical model. The calibrated numerical model was then used to understand the physics involved in this complex subsurface process.In fully water-saturated cores, a major fraction of unreacted carbonate minerals still existed even after 40 pore volumes (PV) of preflush acid injection. Heterogeneity is induced as carbonate-mineral dissolution progresses within the core, creating paths of least resistance, leading to the preferential flow of the incoming fresh acid. This leads to regions of carbonate minerals being untouched during the preflush stimulation stage. A power-law trend, P = aQb, is observed between the stabilized pressure drops at each sequential acid-injection rate vs. the injection rates, where P is the pressure drop across the core, Q is the sequential flow rate, and a and b are constants, with b &amp;lt; 1. An ideal maximum injection rate can be deduced to optimize the preflush stage toward efficient carbonate-mineral dissolution in the damaged zone. An average of 25% recovery of the oil in place (OIP) was seen from preflush experiments conducted on cores with Sorw. In cores with Swi, the oil saturation was reduced during the preflush stage to a similar value as in the cores with Sorw. The oil-phase-viscosity reduction caused by CO2 dissolution in oil and the increase in saturation and permeability to the oil phase resulting from oil swelling by CO2 are inferred as the main mechanisms for any additional oil production beyond residual conditions during the preflush stage. The potential of evolved CO2, a byproduct of the sandstone-acidizing preflush stage, toward its contribution in swelling the surrounding oil, lowering its viscosity, and thus mobilizing the trapped oil has been depicted in this study.

Optimized foam-assisted CO2 enhanced oil recovery technology in tight oil reservoirs

In this paper, foam-assisted CO2 EOR and anti-gas channelling technology are investigated and optimized to enhance tight oil recovery. A series of laboratory experiments, including pressure−volume−temperature, foam generation and evaluation, and coreflood tests, and phase behaviour theoretical mathematical models are performed to evaluate foam agent, analyze anti-gas channelling mechanisms and influential factors, and optimize foam-assisted CO2 EOR technique. The specific CO2 bulk fluid behaviour and phase behaviour in wellbore are determined through experimental and theoretical models. Two distinct stages are found to be divided prior to and after the CO2 gas breakthrough. Most oil productions, which is in the range of 28–40%, occur prior to the gas breakthrough, whereas only additional 5–8% oil is produced after the gas breakthrough. A higher injection rate and/or permeability ratio result in an earlier gas breakthrough and causes less oil to be produced before gas breakthrough while the oil recovery factor slightly increases after the breakthrough by increasing injection rate. Gas diffusion in water-saturated core reach equilibrium faster than that in the oil-saturated core. An overall evaluation parameter is developed to select foam agent. The optimized static condition for the selected foam agent here is approximately 9 MPa at low temperatures while dynamic performance is improved at a higher gas but lower liquid injection rate. The simultaneous water-alternating-gas injection scheme in subsequent of an initial gas injection with liquid−gas ratio of 1:1 performs better than the water-alternating-gas scheme, which is proven to be effective for the core samples with fracture width of 82.67 μm. Finally, the oilfield surface foaming operational system is designed to upscale laboratory research to practical applications with specific operating setup and procedures, which has been applied in the target oil reservoir and performs well as expected.

Impacts of crosslinker concentration on nanogel properties and enhanced oil recovery capability

The use of nanogels, or crosslinked polymeric nanoparticles, has been proposed as a means of improving oil recovery in low permeability reservoirs. Nanogels can transport deep into reservoirs and improve homogeneity due to their small size and deformability. Typically, nanogels are polymerized using monomers and crosslinkers, which transform polymers from linear structures to 3D structures. Nanogel properties — including its swelling ratio and strength — can be fine-tuned by the crosslinker concentration. In this study, we investigated the impacts of crosslinker concentration on partially hydrolyzed polyacrylamide (HPAM)-based nanogels. The effect of the degree of crosslinking on the physicochemical properties of nanogel, the corresponding adsorbing behavior on rock surfaces, and consequently, the oil recovery improvement was studied.The results show the nanogels maintained a lower swelling ratio and less negative charge when synthesized at a higher crosslinker concentration. Higher crosslinker concentrations also resulted in lower dispersion viscosity because of the lower volumetric fraction and weaker interparticle attraction. The relationship between viscosity and dispersion concentration is in an agreement with the Krieger-Dougherty model.Core flooding experiments were conducted under a water-only condition and an oil–water two-phase condition. Nanogels with a lower crosslinker concentration were better able to reduce core permeability. It was discovered that nanogel injection pressure continuously increased in water-saturated porous media, whereas it reached a stable state in a two-phase condition. Core flooding tests in water-saturated cores also indicated that nanogels with a higher degree of crosslinking adsorbed more onto rock surfaces. The adsorption over time of each test fits well with the pseudo-second order equation. In addition, despite similar interfacial reduction capability, nanogels crosslinked to a lesser degree were able to improve oil recovery to a greater extent.

Porous media acidizing simulation: New two-phase two-scale continuum modeling approach

In Recent years some experimental studies have been conducted to investigate the effects of presence of a non-aqueous phase during carbonate acidizing process. Narrower and longer wormholes were observed to be formed when acid is injected into an oil-saturated porous medium, instead of a water-saturated one; which can provide breakthrough earlier with less injected pore volume. However, the mechanisms responsible for these observations had not been comprehensively studied. In this research, a two-phase two-scale continuum (TPTSC) model for simulation of dissolution process during acid injection into carbonate rocks is presented. This model couples two-phase fluid flow equations in porous media and the previously developed two-scale continuum (TSC) model equations for carbonate acidizing. A synthetic case is simulated and the effect of the restricted flow due to various relative permeability values, viscous fingering effects on injected pore volumes to breakthrough; and dissolution patterns are investigated. Our simulation results demonstrate positive effects of two-phase flow and viscous fingering on formation of narrower and longer wormholes. It is observed that pore volumes to breakthrough for an initially high viscosity oil-saturated core is significantly less than pore volumes to breakthrough for an initially water-saturated core. Flow restriction around wormhole due to less relative permeability values and viscous fingering phenomenon can be responsible for gaining lower injected acid volumes to breakthrough. Thus, especially for high viscosity oil reservoir conditions, direct injection of acid to an oil-saturated medium, instead of injecting a pre-flush to push back the saturating oil, can be beneficial.

Investigation of a new application for cellulose nanocrystals: a study of the enhanced oil recovery potential by use of a green additive

Cellulose nanocrystals (CNC) were investigated for use in a potential new application, enhanced oil recovery. Core flooding experiments were performed on outcrop sandstone cores using CNC particles dispersed in low salinity brine (CNC–LS). Core flooding experiments performed on fully water-saturated cores confirm that a majority of viscosity-generating CNC particles successfully traverse the cores at temperature conditions ranging from 60 to 120 °C. Oil recovery tests performed on crude oil saturated sandstone cores at 60 and 90 °C show that when CNC–LS is applied in tertiary mode, ultimate oil recovery increases. During tertiary CNC–LS injection, CNC particles exacerbate differential pressure fluctuations, a phenomenon attributable to log jamming in pore throats, causing remobilisation of oil trapped within pore space regions. Results from the current work indicate that CNC particles dispersed in low saline brine remain promising for implementation in enhanced oil recovery operations.

Effect of fluid–solid coupling on shale mechanics and seepage laws

In this paper, the cores of outcropped black shale of Lower Silurian Longmaxi Fm in the Yibin area, Sichuan Basin, were taken as samples to investigate the effects of extraneous water on shale mechanics and seepage laws during the production of shale gas reservoirs. Firstly, the development of fractures in water saturated cores was observed by using a VHX-5000 optical superdepth microscope. Secondly, water, formation water and slick water, as well as the damage form and compression strength of water saturated/unsaturated cores were investigated by means of a uniaxial compression testing machine and a strain testing & analysis system. Finally, the effects of fluid–solid coupling on shale gas flowing performance in different water saturations were analyzed by using a DYQ-1 multi-function displacement device. Analysis on core components shows that the Longmaxi shale is a highly crushable reservoir with a high content of fragile minerals, so fracturing stimulation is suitable for it. Shale compression strength test reveals that the effects of deionized water, formation water and slick water on shale are different, so the compression strength of shale before being saturated is quite different from that after being saturated. Due to the existence of water, the compression strength of shale drops, so the shale can be fractured easily, more fractures are generated and thus its seepage capacity is improved. Experiments on shale gas seepage under different water saturations show that under the condition of fluid–solid coupling, the higher the water saturation is, the better the propagation and seepage capacity of micro-fractures in shale under the effect of pressure. To sum up, the existence of water is beneficial to fracturing stimulation of shale gas reservoirs and helps to achieve the goal of production improvement.

A case study: evaluating low-porosity and ultra-low-permeability Triassic reservoir rocks in the Ordos Basin by the integration of logs and core

An analysis of the characteristics of ultra-low-permeability reservoir rocks and the processes for permeability loss form the basis for establishing high-resolution well log interpretation models. Moreover, this type of analysis is a prerequisite for the effective development of ultra-low-permeability reservoirs. The Chang 7-1 sandstone members of the Triassic Yanchang Group in the Longdong region of the SW Ordos Basin are typical ultra-low-permeability reservoirs and are studied in detail in this paper. A comprehensive methodology of evaluating the ultra-low-permeability reservoir is developed based on geological information and well logging data. First, pore structure characteristics are analysed in depth using core observations, cast thin sections, scanning electron microscopy and mercury injection porosimetry. The mechanism behind the formation of ultra-low permeability in a reservoir rock, and its controlling factors, are also clearly determined. Second, from the above results and the pore structure characteristics in the study area, the flow-zone indicator (FZI) is selected as the key reservoir modelling parameter to establish permeability models that can reflect different pore structure types and improve precision compared to non-classification pore structure models. In addition, conductivity experiments with water-saturated cores confirm that the additional conduction phenomenon of clay minerals has little impact in terms of reducing reservoir resistivity and, consequently, the Archie formula is found to be reliable for ultra-low-permeability rocks with porosities greater than 5% in the Chang 7-1 reservoir. Three types of well log interpretation models, such as permeability, oil saturation and porosity, are established for the ultra-low-permeability reservoirs using FZI as a classifier in the research area. These models reduce the relative errors to less than 10% and performed well for the ultra-low-permeability Chang 7-1 sandstones. This study contributes to the evaluation of ultra-low-permeability reservoir rocks and also generates fit-for-purpose log evaluation models to guide completion interval selection.