Oil-saturated Samples Research Articles

Role of Rock Saturation Condition on Rock-Mud Interaction: Sandstone Geomechanics Study.

The rock saturation condition affects the rock elastic and strength characteristics due to the role of fluid–rock interaction. However, the role of this parameter has not been studied well for mud–rock exposure during drilling operations. Hence, this study targets to assess the role of different rock saturation conditions on the rock geomechanics changes during the rock exposure for the drilling fluids. During the drilling operation, the mud filtrate invades the drilled formation pore system and replaces the saturating fluid and consequent alterations occur for the rock elastic moduli and failure properties. The current study employed Berea Buff sandstone rock type with different saturation conditions (brine-saturated, dry, and oil-saturated) to interact with drilling mud (water-based) through the filtration test to mimic the downhole rock–mud exposure under pressure, temperature, and time conditions. Extensive laboratory analysis was accomplished that covered the scratching test to get the strength of rock samples, acoustic data determination, elastic moduli evaluation, and scanning electron microscopy to assess the internal alterations of the rock pore system. The obtained results showed that the oil-saturated sample showed the least filtration characteristics for the rock–mud exposure and the best condition to maintain the rock strength from deterioration compared to the dry and brine-saturated samples. The rock strength showed a weakening behavior for the brine-saturated and dry samples by 5 and 18% respectively, while the oil-saturated sample showed only a 2% strength reduction after the mud exposure. Poisson’s ratio showed a 21% increase for the brine-saturated sample and the dry sample showed a small increase from 0.2 to 0.22, while the oil-saturated sample maintains a stable Poisson’s ratio at 0.24. Young’s modulus showed an increase for the dry and brine-saturated rock samples by 10 and 7%, respectively, while a 25% reduction for the oil-saturated. The spectrometry analysis results showed the internal changes in the rock samples’ pore system for the brine-saturated and dry samples, while the oil-saturated sample showed no internal changes that maintain the rock structure and strength after the mud exposure.

Influence of water on deformation and failure of gypsum rock

While water is known to significantly reduce the strength of rocks, there remains a paucity of data on water-weakening of gypsum. Here, we quantify water-weakening in a natural gypsum facies from Monferrato (Italy) by performing experiments on nominally dry, oil-saturated, and water-saturated samples. Uniaxial and conventional triaxial experiments revealed significant water-weakening in Monferrato gypsum as well as a strong strain-rate dependence of uniaxial compressive strength. Moreover, uniaxial creep tests showed significant time-dependent deformation in samples saturated with sulphate over-saturated water, but not in dry and oil-saturated samples. The creep phenomenology is similar to that observed in other rock types and is consistent with stress-corrosion microcracking, which is supported by our microstructural observations. However, we systematically recorded more inelastic strain in samples deformed at low strain-rates suggesting that additional mechanisms were also active. Comparing our new data on short-term strength with published results for other rock types, we conclude that, when saturated with water in equilibrium with the rock, weakening in gypsum is not notably higher than in other rocks and is partially due to a reduction of fracture toughness in the presence of water.

Pore Structure and Wettability of Lacustrine Shale With Carbonate Interlayers in Dongying Depression, Bohai Bay Basin, East China

Shale samples with carbonate interlayers have attracted more and more attention in shale oil exploration of lacustrine shale in China, and the characterization of pore structure and wettability of these shales are significant to the study of shale-oil enrichment and effective exploitation. In this work, by examining six shale samples with carbonate interlayers of Shahejie Formation in East China, the pore structure and wettability characteristics of shale are characterized by means of thin section petrography; X-ray diffraction mineralogy; total organic carbon (TOC) analyses; scanning electron microscopy (SEM) imaging; air-liquid contact angle for wettability; as well as N2 physisorption, mercury intrusion porosimetry, and nuclear magnetic resonance (NMR) for pore structure. The results show that the main mineral contents are carbonate (with an average of 51.4%) and clay minerals (mainly mixed-layer illite-smectite). The average TOC content is 2.90%, and there is a strong correlation between TOC and dolomite content. In addition, the obvious layered structure is observed by thin section and SEM methods. The pores below 200 nm with ink-bottle shapes are obviously smaller than those of marine shale, and the pore throats are mainly below 50 nm; however, there are also some micrometer-sized cracks. The droplet contact angle measurement shows that the shale is mainly lipophilic, while moderately hydrophilic, at millimeter observational scales. The NMR T2 spectra of water- and oil-saturated samples have an obvious feature of three peak characteristics, as the pore size-associated wettability of these samples can be divided into three stages: water-wet (0.01–1 ms), oil-wet (1–40 ms), and mixed-wet (>40 ms) in terms of relaxation time of the NMR T2 spectrum. The proportion of the second main peak of T2 spectra (P2) for dodecane-saturated samples is directly proportional to the TOC content, and the relationship between P2 and mineral composition is consistent with water-saturated samples.

An experimental approach on calcarenite reservoir dilation factor

The time of flight of a plane wavefront generated from an acoustic pulse is expected to decrease when the medium length between the wave emitter and receiver is shortened. This simple idea is extrapolated to the case of reservoir compaction in order to obtain a geophysical parameter R (dilation factor) that relates the rock deformation to the variation of time of flight (also called time-lapse time shift in 4D seismics) or acoustic velocity of a plane wave propagating in the same direction of deformation. Interpretation of a few laboratory compressive tests with simultaneous ultrasonic acquisition, performed on oil-saturated calcarenite samples, are presented and discussed. The samples were subjected to several stress regimes and simultaneous ultrasonic acquisitions. Despite the formerly ultrasonic acquisition rate limitations, it was possible to obtain R values for various lateral-vertical stress ratios for each sample's linear and nonlinear stress-strain trends.

Wettability Alteration of Carbonate Reservoirs Using Imidazolium-Based Ionic Liquids.

The wettability of the rock–oil–brine system plays a major role in enhanced oil recovery (EOR), particularly in the harsh environments of carbonate reservoirs. Most of these formations were identified as strongly oil-wet, and sometimes a few are intermediate-wet. Hence, it is highly necessary to alter such an oil-wet rock matrix to a water-wet matrix in order to improve the oil production. Consequently, it is important to investigate the wetting and wettability dynamics of the rock–oil–brine system for both static and dynamic cases. Thus, in this study, we investigated the effect of four various imidazolium-based ionic liquids (ILs) on the wettability alteration of the rock–oil–brine system by measuring the contact angles. Herein, we have screened various parameters, such as the rock type (brine-saturated and oil-saturated), type of IL, IL concentrations (0–1000 ppm), temperature (25–100 °C), pressure (14.7–3000 psi), and salinity (TDS: 67,500–240,000 ppm). The measurement of the static contact angle was found to be altered from 85.5 to 49.4° with the addition of 500 ppm of ILs in the brine-saturated sample, and for the oil-saturated sample, it was altered from 150.9 to 99.2°. This indicates that ILs have a huge influence on shifting the rock wettability more toward water-wet, which in fact is more favorable for the EOR operation. Later, we studied the dynamic wettability alteration of the rock–oil–brine system, in which we measured the transient changes in the contact angle while displacing the brine with an IL solution in situ. It was observed that the oil droplet deformed slightly and was dragged toward the base fluid (IL solution) with time, and this implied the changes in the contact angle from 150.9 to 118.5° with 500 ppm of IL, [C12mim]+[Cl]−. Though this has a relatively lesser impact as compared to the static experiment, this could be considered to be more realistic to correlate with coreflood experiments. Further, to understand the mechanism of this wettability dynamics, we have measured the oil–water interfacial tension and the ζ-potential of various systems and observed that their results were backed up by our wettability studies. Overall, the combined forces of interfacial tension reduction, capillary alterations, and IL interactions with rocks and oils have caused this wettability alteration. Conclusively, the results of various experiments that are performed in this study are more meaningful, and it is evident that ILs favor the successful EOR implications.

Quantifying the Effect of De-Emulsifiers on Acid Treatment in Carbonate Formations

Matrix acidizing is a highly successful, effective, and relatively inexpensive approach to enhancing well productivity in carbonate formations. Accordingly, there has been little motivation to address the ways to optimize the acid stimulation process better. Acid-in-oil emulsions that form during this process cause one of the most challenging problems that negatively impact the performance and deliverability, especially when these emulsions are highly stable over extended periods. Such stable emulsions can plug the flow path of oil causing high resistance to flow and potentially reducing well productivity. De-emulsifiers are some of the most widely used acid additives targeting the reduction of emulsion stability. However, there is doubt in the research community on whether there is enough shear mixing that can cause the formation of emulsions inside the rock matrix. Besides, the effectiveness of de-emulsifiers in eliminating such emulsions in the pore space has not been investigated. In the current oil price market, there is a need to be more vigilant regarding the cost of well stimulation and the added value from the various additives. While laboratory work on matrix acidizing in carbonate formations is abundant, the work on oil-saturated samples is rare, and therefore, the effect of emulsions on the acidizing process has not been widely documented. In this work, we present a stacked study of bottle tests and core flooding tests designed to investigate the de-emulsifiers’ role in the rock matrix. The results reveal that (1) emulsion-risk in the pore space is real, and (2) the addition of de-emulsifiers to the acid allows for efficient backflow of oil, revealing an improvement in the performance of the acidizing treatment.

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.

Surfactant selection for enhanced oil recovery based on surfactant molecular structure in unconventional liquid reservoirs

Experimental observations and field applications have revealed that surfactants have significant potential to enhance oil recovery in unconventional liquid reservoirs (ULR). This study is designed to determine the effect of surfactant molecular structure on wettability alteration as measured via the contact angle (CA). The relation between contact angle and spontaneous imbibition in enhanced oil recovery (EOR) is determined. A systematic workflow is proposed for surfactant selection based on maximizing wettability alteration. The mechanism of wettability alteration is investigated as a function of the hydrophobic tail group and the hydrophilic head group of various surfactant structures.Contact angle and interfacial tension (IFT) were measured for crude oil and oil-saturated samples from the Eagle Ford and Wolfcamp formations using various surfactant formulations. A novel workflow to test surfactant stability defined as retention of surfactant layers on the rock surface was proposed to evaluate the duration of wettability alteration. Surfactants exhibiting maximum wettability alteration were utilized to perform Surfactant Assisted Spontaneous Imbibition (SASI) to assess their performance on improving oil recovery. A comprehensive analysis was performed to demonstrate the correlation between surfactant performance and molecular structure.The primary production mechanism of surfactant EOR in ULR is highly influenced by wettability alteration, IFT reduction, and the retention of surfactant on the rock surface. CA and IFT measurements were performed with anionic, cationic, nonionic, and zwitterionic surfactants to evaluate the effectiveness of these surfactants. Results indicate that both the hydrophilic head and hydrophobic tail of surfactants have significant effects on wettability alteration. Surfactants with longer tails could effectively alter the wettability of rock from oil-wet to more water-wet and reduce the IFT to a lower range. Surfactant stability tests demonstrate that surfactants with greater stability are more favorable for spontaneous imbibition.In this study, nonionic surfactants generally show better performance than ionic surfactants. The performance of nonionic surfactant is governed by the number of Ethylene Oxide (EO) groups. It is attributed to the fact that nonionic surfactants have greater adsorption density and a more stable adsorption layer than ionic surfactants. At reservoir temperature, some nonionic surfactants reach cloud points that obscure CA measurements and reduce the efficacy of surfactants. The stability test presented in this work provides a method to assess the duration of wettability alteration of rock surface using those nonionic surfactants.The proposed selection method is validated by the results of surfactant screening, stability tests, and SASI experiments. This study addresses the importance of surfactant structure and stability during EOR operations in ULR. This work provides a more definitive interpretation of the surfactant molecular structure on rock-fluid interactions in ULR.

Heat capacity and thermal diffusivity of heavy oil saturated rock materials at high temperatures

As well-known the rate of heat extraction depends on the thermal conductivity, $$Q = - \, \lambda \left( T \right){\text{grad }}T$$ , and the fluids flow characteristics, while amounts of heat recovery depends on heat capacity of reservoir rocks, $$Q = \left( {1 - \phi } \right)\rho C_{\text{P}} T$$ , where $$\phi$$ is the porosity. In the present work the laser-flash (LFA 457) and differential scanning calorimeter (DSC 204 F1) techniques were employed on a heavy oil saturated natural rock sample for accurate measurements of the thermal diffusivity and heat capacity over a temperature range from (294 to 1024) K and from (306 to 771) K, respectively. The density of the sample at room temperature was 2300 kg m−3 and the porosity was 17.1%. The sample for the present study comes from Russian Oil Field (Eastern Siberia, Russia). The expanded uncertainty of the thermal diffusivity and heat capacity measurements at the 95% confidence level with a coverage factor of k = 2 is estimated to be 3% and 1%, respectively. At low temperatures (below approximately 373 K), the sharp increases (up to η = 2.3) of the thermal diffusivity anisotropy was observed. Based on the measured thermal diffusivity and heat-capacity data, thermal conductivity of the same oil saturated rock sample was calculated using the thermodynamic relation $$\lambda = a\rho C_{\text{P}}$$ . The effect of temperature and various physical and chemical processes, such as thermal decomposition (chemical reactions) of pore heavy oil occurred in the sample during the heating in distinct temperature ranges were studied. The effect of pore heavy oil decomposition (under thermal stress) on the measured values of heat capacity and other thermophysical properties of rock sample at high temperatures (around 700 K) was experimentally observed. Also, we experimentally found weak temperature maximum of the heat-capacity of the sample under study in the low temperature range (around 380 K).

Application of wavelet analysis of X-Ray computed tomography histogram for phase segmentation

With the development of unconventional resources, the standard task of evaluation the porosity and oil saturation needs a new approach. Heavy oil and bitumen can act as the cement in many sand reservoirs, which excludes the use of standard measuring techniques. A method for phase segmentation and estimating the porosity and oil saturation of heavy oil reservoirs, based on wavelet analysis of X-ray computed tomography histogram was proposed. Its advantages are reducing human influence on phase thresholding and the ability to work with loose sand reservoirs, for which it is not possible to use standard assessment methods. The main problem found for this method is the need for high detailing of segmentation objects since a large amount of noise and transition voxels adversely affect class recognition and quantitative interpretation. The application of wavelet analysis approach for naturally heavy oil saturated samples requires high-resolution microCT (less than 5 µm) and high oil saturation of the samples.

Laboratory study of oil saturation and oil/water substitution effects on a sandstone’s modulus dispersion and attenuation

Using the stress–strain oscillation method, we conducted experiments on a sandstone over a frequency range of 1–100 Hz at a differential pressure of 5 MPa to investigate the effects of oil saturation and oil/water substitution on modulus dispersion and attenuation. We first saturated the sandstone with a low viscosity oil (2#) at different saturation degrees, then replaced the 2# oil with a more viscous oil (68#) and finally injected distilled water in the oil-saturated sample. Young’s modulus, Poisson’s ratio and extensional attenuation were measured during these saturation processes. The measured moduli of this sandstone, when saturated with the 2# oil at different saturation degrees (0% to 100%) or when fully saturated with the 68# oil, manifest little dispersion over the frequency range of 1–100 Hz, and low attenuation was observed. The measured bulk modulus for the oil-saturated sandstone agrees well with the prediction of Gassmann’s fluid-substitution theory, suggesting that wave-induced fluid flow (WIFF) plays an insignificant role in control of the bulk modulus when the sandstone is filled with oil. However, as oil saturation and viscosity increase, the shear modulus keeps increasing, violating the Gassmann’s fluid-substitution theory, which may be caused by the viscous coupling mechanism. When water was injected into sandstone fully saturated with the 68# oil, distinct modulus dispersion and attenuation were observed. The characteristics of the modulus dispersion and attenuation are consistent with mesoscopic WIFF theory, indicating that mesoscopic WIFF is the main cause of modulus dispersion and attenuation for this sandstone saturated with oil–water mixture at seismic frequencies.

Imaging of compositional gradients during in situ emulsification using X-ray micro-tomography

The rate of emulsification in surfactant/oil/water systems is influenced by transport of chemicals and mixing of the fluid phases. In porous media applications, complex flow regimes are generated due to three-dimensional connectivity and irregular cross-sections of the pores facilitating the mixing for emulsification. The properties of the resulting emulsified phase depend on the interplay of flow, mixing and emulsification kinetics of the surfactant/oil/water system. Emulsification can be relatively quick. Direct visualization of the process and compositional gradients in three-dimensional pore space during flow requires imaging at few seconds time intervals.In this study, a flow unit was integrated in a synchrotron beamline-based fast X-ray computed micro-tomography set-up. Non-destructive three-dimensional visualization of multi phase flow inside a porous rock at flow conditions became viable. An oil saturated rock sample was first flooded with water, followed by surfactant solution to mobilize the remaining oil by miscible displacement. The sample was continuously imaged during injection; the scans were made at time intervals of 7–60 s.The presence of an emulsified phase in addition to the oil and the aqueous phases required a more advanced image processing workflow compared to the workflows used for the immiscible fluid systems. A newly developed image processing technique was adopted; the grey levels in the images were correlated with the local oil content in the emulsified fluid regions. The visual extractions of the pore space showed that the emulsification occurred within seconds. Compositional gradients were observed in the emulsified phase as the injected surfactant solution reached the remote locations in the pore space. While a significant fraction of the oil was displaced within few seconds, the compositional gradients persisted over several millimeter length for several minutes, illustrating a sequence of mobilization and solubilization of the oil phase. The ability to interpret such compositional gradients in real time in porous space brings capability to study interfacial phenomena in applications where in situ emulsification occurs under flow.

The effect of saturation conditions on fracture performance of different soundless cracking demolition agents (SCDAs) in geological reservoir rock formations

Fracture stimulation using soundless cracking demolition agents (SCDAs) is a potential alternative technique to induce high-density fractures in sedimentary reservoir-rock as an auxiliary technique to improve the efficiency of enhanced oil and gas recovery efficiencies. However, to date, its application has been limited to fracture stimulation in dry rock masses. Therefore, using modified SCDAs, which can be used for underwater rock fracturing, a series of experiments was conducted to investigate the fracturing performance of SCDAs in saturated rock masses. 18 coarse-grained sandstone specimens were saturated in water, oil, and NaCl brine and fractured using three different SCDA types: a standard SCDA (S1), and two modified for underwater application (S2) and accelerated reaction rate (S3). Then, the fractured samples were scanned in the Australian Synchrotron, and the fractures were quantified using Avizo 9.0.1. The fracture initiation time and the total fracture network length and volume were found to be dependent on the saturated pore fluid of rock. Water saturation of samples increased the fracture initiation time by 16.5%, 24.1% and 13.68% for S1, S2, and S3 type SCDAs respectively and reduced the fracturing potential of SCDA by 59.5%, 32.49% and 66.67% compared to dry samples. This reduction was less apparent in oil-saturated samples as the high pore fluid viscosity of oil-saturated samples aid fracturing, which is explained by the Poiseuille equation. Increasing salinity in the saturation fluid from 0% to 12.5% was favourable for the fracturing efficiency of SCDAs because of the formation of CaCl2 in the pore fluid, which accelerates the reaction of SCDA. Fracture orientation also changed depending on the saturation fluid, which was again governed by the variation in reaction rate in SCDAs under different saturation conditions.

Influence of Water–Oil Saturation on the Fracture Process Zone: A Modified Dugdale–Barenblatt Model

The wetting and nonwetting fluid saturations in porous reservoirs always change during long-term injection and production. The fracture process zone (FPZ) is a prominent feature in the rock fracture process. If the FPZ properties are influenced by pore fluids, the process of hydraulic fracturing will change greatly. The existing models do not consider the role of pore fluid when characterizing the FPZ. In this paper, a modified Dugdale–Barenblatt (D–B) model with capillary pressure is proposed. The model reflects the fact that the FPZ length decreases nonlinearly with the increase in capillary pressure, and it reveals the mechanism of capillary pressure on the equivalent fracture cohesion in the FPZ, which affects the FPZ length. Three-point bending tests were carried out on sandstone under various fluid saturations through digital image correlation (DIC), acoustic emission (AE), and scanning electron microscope (SEM). It was found that the FPZ length of the water–oil-saturated samples was 30–50% smaller than that of water-saturated/oil-saturated samples due to the capillary pressure effect, and the modified D–B model was well consistent with the experiments. The AE behaviors of different saturated samples were not the same: The cumulative AE signals changed abruptly at 90% of the peak load for the water–oil-saturated samples and at 50% of the peak load for water-saturated samples. This demonstrated that the effect of capillary pressure was more obvious than the weakening effect of microstructural damages. The significant influence of capillary pressure on FPZ requires continuous recognition in hydraulic fracturing design.

Effect of native and injected nano-particles on the efficiency of heavy oil recovery by radio frequency electromagnetic heating

Previous attempts of EM heating have been made on the estimation of reservoir heating capabilities through numerical or analytical modeling. Experimental efforts, however, are needed, especially to test the oil property changes under EM radiation, temperature rise profile, and its effects on oil recovery. In this study, we introduced a conceptually scaled model (125×50×40cm) filled with sand to investigate the feasibility of EM heating for heavy oil recovery. For this purpose, a microwave antenna with a frequency of 2.45GHz and 2kW Magnetron based power generator was used to obtain the EM waves. Temperatures at different distances from the antenna were measured by fiber optic temperature sensors. Oil recovery experiments were conducted by placing the oil saturated sand samples in Buchner funnels at different distances from the antenna. The effect of temperature on viscosity of crude oil before and after exposure of EM radiation was also examined through the oil samples in Buchner funnels located in the model. The produced gases and oil collected were analyzed through GC to ensure the loss of component from the original oil and upgradation study. The experiments were repeated using Ni and Fe nanoparticles with oil and silica bead mixture, which can absorb EM waves. They improved the efficiency of the methods yielding a faster heating and thereby a quicker viscosity reduction. Finally, the experiments were repeated with high clay contents representing shale reservoirs. The recoveries and the change in oil properties were correlated to the power of the EM source and distance from this antenna. Temperature was raised by Ni nanoparticles (up to ~200°C) and therefore higher oil recovery (~30% of OOIP) was also obtained with Ni nanoparticles. Experimental observations and quantitative analyses could provide a vision for further development of EM heating as an alternative for situations where aqueous heating is not feasible.

Shear modulus and damping ratios of transparent soil manufactured by fused quartz

The mixture of fused quartz and pore fluid with the same refractive index has been used as a synthetic transparent soil to mimic the behavior of natural soil. Previous research has focused on its static properties. In this paper, the dynamic properties of fused quartz (dry samples and oil saturated samples), including shear modulus and damping ratio, were examined through a series of resonant column tests and dynamic torsional shear tests. It was found that fused quartz has similar dynamic behavior to that of natural soil. With the test results, fused quartz shows a great potential as a substitute for natural soil and is expected to be widely used in dynamic transparent soil model tests.

Advances in Understanding Wettability of Tight Oil Formations: A Montney Case Study

Summary This paper presents comprehensive rock/fluid experiments, by use of reservoir rock and fluids, to investigate wetting affinity of the Montney (MT) tight oil play in the Western Canadian Sedimentary Basin. Wettability characterization is essential for selecting optimum fracturing and treatment fluids by completion engineers and for selecting appropriate relative permeability and capillary pressure curves by reservoir engineers. Application of the conventional techniques for wettability evaluation of tight rocks is challenging primarily because of their extremely low permeability and complex pore structure. The objective of this paper is to develop an alternative laboratory protocol for evaluating the wettability of tight oil rocks reliably. First, we conducted systematic spontaneous-imbibition tests on fresh core samples from two different wells drilled in the MT formation. We measured the air/brine, air/oil, and brine/oil contact angles for all samples. We used the end pieces of the samples to conduct scanning electron microscopy (SEM) and analysis of the elemental mapping, or energy-dispersive X-ray spectroscopy (EDS). Finally, we investigated the spontaneous imbibition of brine (or oil) into the samples partly saturated with oil (or brine). Both oil and brine spontaneously imbibe into the fresh samples, composed of quartz, carbonates (dolomite/calcite), clay minerals, feldspars, and organic matter. The results indicate that the effective pore network exhibits a mixed-wet behavior. Moreover, brine spontaneously imbibes into and forces the oil out of the oil-saturated samples, whereas oil cannot imbibe into the brine-saturated samples. This indicates that in the presence of both oil and brine, the rock affinity to brine is higher than that to oil.

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

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

An extended model for ultrasonic-based enhanced oil recovery with experimental validation

This paper suggests a new ultrasonic-based enhanced oil recovery (EOR) model for application in oil field reservoirs. The model is modular and consists of an acoustic module and a heat transfer module, where the heat distribution is updated when the temperature rise exceeds 1°C. The model also considers the main EOR parameters which includes both the geophysical (i.e., porosity, permeability, temperature rise, and fluid viscosity) and acoustical (e.g., acoustic penetration and pressure distribution in various fluids and mediums) properties of the wells. Extended experiments were performed using powerful ultrasonic waves which were applied for different kind of oils & oil saturated core samples. The corresponding results showed a good matching with those obtained from simulations, validating the suggested model to some extent. Hence, a good recovery rate of around 88.2% of original oil in place (OOIP) was obtained after 30min of continuous generation of ultrasonic waves. This leads to consider the ultrasonic-based EOR as another tangible solution for EOR. This claim is supported further by considering several injection wells where the simulation results indicate that with four (4) injection wells; the recovery rate may increase up-to 96.7% of OOIP. This leads to claim the high potential of ultrasonic-based EOR as compared to the conventional methods. Following this study, the paper also proposes a large scale ultrasonic-based EOR hardware system for installation in oil fields.

Application of Biosurfactants to Wettability Alteration and IFT Reduction in Enhanced Oil Recovery From Oil–Wet Carbonates

To obtain potentially applicable microorganisms to an effective in situ microbial enhanced oil recovery operation, bacteria that were compatible with the harsh conditions of a petroleum reservoir were isolated from a crude oil sample. The application of an oil spreading technique showed that all of the isolates were capable of producing biosurfactants from both the glucose and crude oil as carbon sources. The secreted biosurfactants could at least reduce the surface tension 20 mN/m and for one of the isolates; the surface tension value dropped below 40 mN/m. In addition, the contact angle measurements revealed that the produced biosurfactants could effectively alter the wettability of the oil saturated rock samples. At last, the effect of isolates and their biosurfactants on improving oil production from oil saturated rock samples was investigated. It was observed that the presence of bacteria in the system could increase the amount of produced oil in comparison with the case where cell free biosurfactants were utilized.