Wettability Alteration Of Rock Research Articles

Influence of Henna Extracts on Static and Dynamic Adsorption of Sodium Dodecyl Sulfate and Residual Oil Recovery from Quartz Sand.

The application of surfactant flooding for enhanced oil recovery (EOR) promotes hydrocarbon recovery through reduction of oil-water interfacial tension and alteration of oil-wet rock wettability into the water-wet state. Unfortunately, surfactant depletion in porous media, due to surfactant molecule adsorption and retention, adversely affects oil recovery, thus increasing the cost of the surfactant flooding process. Chemical-based materials are normally used as inhibitors or sacrificial agents to minimize surfactant adsorption, but they are quite expensive and not environmentally friendly. Plant-based materials (henna extracts) are far more sustainable because they are obtained from natural sources. However, there is limited research on the application of henna extracts as inhibitors to reduce dynamic adsorption of the surfactant in porous media and improve oil recovery from such media. Thus, henna extracts were introduced as an eco-friendly and low-cost sacrificial agent for minimizing the static and dynamic adsorption of sodium dodecyl sulfate (SDS) onto quartz sand in this study. Results showed that the extent of surfactant adsorption was inversely proportional to the henna extract concentration, and the adsorption of the henna extract onto the quartz surface was a multilayer adsorption that followed the Freundlich isotherm model. Precisely, the henna extract adsorption on quartz sand is in the range of 3.12-4.48 mg/g (for static adsorption) and 5.49-6.73 mg/g (for dynamic adsorption), whereas the SDS adsorption on quartz sand was obtained as 2.11 and 4.79 mg/g at static and dynamic conditions, respectively. In the presence of 8000 mg/L henna extract, SDS static and dynamic adsorption was significantly reduced by 64 and 82%, respectively. At the same conditions, the residual oil recovery increased by 9.2% over normal surfactant flooding. The study suggests that the use of henna extracts as a sacrificial agent during SDS flooding could result in the reduction of static and dynamic adsorption of surfactant molecules on quartz sand, thus promoting hydrocarbon recovery from sandstone formations.

Experimental study about the effect of SiO2 nanoparticle in surfactant performance on IFT reduction and wettability alteration

Recently, serious attention to the high potential of nanotechnology in the enhanced oil recovery (EOR) processes have been attracted. In this study, the effects of addition of SiO2 nanoparticle into the aqueous solutions containing octyl phenol ethoxylate (Triton-x100), sodium lauryl sulfate (SLS), and octyl pyridinium chloride ([C8Pyr][Cl]) on the interfacial tension (IFT) reduction, wettability alteration of carbonate rock, and the spreading coefficient were investigated. EDX and FeSEM analysis were taken on the rock that indicate the dolomite nature of the rock sample. The equilibrium IFT and contact angle values of different cases were measured in two series (i.e. with and without SiO2 nanoparticles). It is found that the performance of SiO2 nanoparticle remarkably affected by surfactants type and their combination. SiO2 could not have a positive effect on the IFT reduction and wettability alteration and had an adverse effect on the performance of some surfactants. In more details, SiO2 nanoparticles was able to slightly improve the TiO2 surfactant performance by falling the IFT value from 2.8 to 1.5 mN/m, while it did not have a significant effect on the performance of Pyr surfactant by changing the IFT value from 14 to 13.3 mN/m. The performance order of IFT reduction and wettability alteration was completely different as the lowest IFT and contact angle values were observed for the SLS in the presence of SiO2 (IFT reduction from 0.36 to 0.1 mN/.m) and Tr in the absence of SiO2 (wettability change from 49º to 32.5º), respectively. However, SiO2 nanoparticles have a favorable effect on the spreading coefficient of SLS, Pyr, SLS+Pyr, and SW; among them, the best performance was observed for SLS with spreading coefficient (Sc) value of − 0.06 mN/m.

Effect of UiO-66-NH2/TiO2 nano-fluids on the IFT reduction and their use for wettability alteration of carbonate rocks

One new technique to change the wettability of rocks (carbonate) is sea water (SW) flooding and nano-composite flooding. In this regard, this study investigated the performance of a new synthetic nano-composite called UiO-66-NH2/TiO2 (UT). In this study, this nano-composite is used next to SW. Generally, scanning electron microscopy (SEM), X-ray Powder Diffraction (XRD), Energy Dispersive X-ray Spectroscopy (EDS), and Brunauer-Emmett-Teller (BET) analyses investigated synthetic nano-composite physical and chemical properties. A comparative study of the effect of the synthesized Nano-fluids was performed using interfacial tension (IFT), contact angle (CA), and core flooding experiments. In this experimental study, SW contains Ca2+ and SO42− ions. Generally, nano-composite samples with differents concentrations (0.03 wt% and 0.3 wt%) dispersed in a base-fluid (BF) with varied salinities were prepared. Results showed that this sea-water (SW) + 0.3 wt%UT could reduce interfacial tension from 22 (mN/m) to 3.3 (mN/m) and CA from 118° to 37°. Generally, the interfacial tension between nano-fluids and crude oil is also a function of nano-fluid concentration and BF salinities. On the other hand, oil recovery results using the core flooding test show that SW and 0.3 wt% UT are high efficient than other concentrations. Thus, by injecting this nano-fluid (SW + 0.3 wt% UT), the ratios of oil recovery through the flooding process in the first and second core plugs to the total oil recovery increased by 24.8% and 26%, respectively. In the end, SW + 0.3 wt% UT showed the best performance in relation to increased oil recovery. This study offers new findings that can help oil recovery by understanding SW technology with nano-composite in carbonate reservoirs.

Formulation and evaluation of a new multi-functional fracturing fluid system with oil viscosity reduction, rock wettability alteration and interfacial modification

Low permeability heavy oil reservoir has the characteristics of poor physical properties and poor oil mobility, and its primary production is very limited.Based on the synergistic mechanism, the multi-functional composite fracturing fluid system HC-5 was constructed in this study, which combines fracturing, viscosity reduction, wettability change, and interface modification. Taking a low permeability heavy oil block in Changqing Oilfield as an example, the oil recovery of the new multifunctional composite fracturing fluid system was evaluated. The results show that the viscosity reduction should not be used as a single evaluation index for enhanced oil recovery in heavy oil reservoirs, and the improvement degree of the water–oil mobility ratio is more significant.Wettability reversal can change capillary resistance into displacing force and affect the influence of interfacial tension.The interfacial tension is not the smaller the better, the contribution of reducing interfacial tension to enhancing oil recovery has decreased after reaching a low value (10−2 mN/m), even lower than the contribution of mobility ratio, so it is not recommended to blindly pursue extremely low interfacial tension and the synergistic effects of various reasons should be played to obtain the best result.In addition, by adding polymer, the viscoelasticity can be used to increase the microscopic pull force and expand the macroscopic sweep volume. The field test of 10 volumetric fracturing wells provides that the fracturing fluid system can significantly increase the primary production of the well by 20–25%.

Pore-Scale Investigation of Low-Salinity Nanofluids on Wetting Properties of Oil Carbonate Reservoir Rocks Studied by X-ray Micro-Tomography

Low-salinity surfactant nanofluids have recently shown promising results in the wettability alteration of reservoir rocks from oil-wet state towards more water-wet state. However, the investigation of pore-level interactions of nanofluids injection in real oil carbonate rocks at reservoir conditions, which determines the overall fluid dynamics, is lacking. Therefore, in this work, we studied the effect of nanoparticles augmented low-salinity surfactant flooding on the wettability alteration of hydrophobic carbonate rocks with harsh reservoir conditions via X-ray micro-tomography. The designed experiment scheme involved core flooding with an X-ray transparent core-holder developed for studying the flow properties of fluids at the micro level (pore scale). The wettability was quantified by measuring the differences in contact angles after the injection of low salinity, low-salinity surfactant, and low-salinity surfactant nanofluid. The findings illustrate that surfactant flooding with silica nanoparticles had a more pronounced influence on the contact angle among other injected fluids. The contact angle of the rock fell from 144° to 49°, corresponding to the water-wet conditions of carbonate rocks. The results show that the addition of a low concentration (0.005 wt.%) of SiO2 nanoparticles was enough for wettability changes in oil carbonate rocks. This study illustrates that a combination of surfactant, low-salinity, and nanoparticle features has a more pronounced effect on the three-phase contact angle than if applied separately.

IMPROVING THE PERFORMANCE OF ZNO NANOPARTICLES FOR EOR IN HIGH-TEMPERATURE AND HIGH SALINITY CARBONATE RESERVOIRS

The main challenge of the application of nanofluids for enhanced oil recovery (EOR) in carbonate reservoirs is to maintain colloidal stability under reservoir conditions with high salinity and high temperature. In this study, we address this issue by increasing the stability and hydrophilicity of ZnO nanoparticles by adding TTIP. Adding TTIP on the surface of ZnO nanoparticles results in an increase in the hydrophilic heads in the final product. Then, these nanoparticles are used to coat carbonate rock surfaces to change their wettability. The coated rock plates are obtained by aging them in nanofluids. The modified ZnO-based coatings show to be more effective for wettability alteration purposes compared to the conventional ZnO coating. The un-coated rock plate is strongly oil-wet, where the water and n-heptane droplets contact angles on this surface are 168° and 0°, respectively. After aging the rock samples in nanofluids, superhydrophilic coatings form on the superhydrophobic surfaces. The rock surface before and after treatment, as well as the synthesized nanoparticles, are characterized by scanning electron microscope (SEM), x-ray diffraction (XRD), and Fourier-transform infrared spectroscopy (FTIR) analyses. Results of this study indicate the possibility of using the materials for wettability alteration of oil-wet carbonate rock in the EOR process. The results of core flooding tests demonstrate that the oil recovery enhances significantly through the nanofluid flooding.

Digital rock workflow to calculate wettability distribution in a reservoir rock

Wettability has a strong influence on multi-phase flow behavior through reservoir rock. Reservoir rocks tend to have spatially varying wettability. Prior to contact with oil, rocks are almost always naturally water-wet. As oil invades the pore-space over geologic time, the initial water-wet state may be altered in certain locations due to adhesion of substances within the oil phase to the grains. Mechanisms of wettability alteration depend on various properties such as pressure, temperature, mineral chemistry, surface roughness and fluid composition. In this study wettability alteration in a reservoir rock is studied through direct simulation using multiphase Lattice Boltzmann method where the computational grid is constructed from segmented micro-CT images of the rock sample. The pore-grain interface is defined by a triangulated surface mesh for accurate fluxes near boundary and local curvature calculation. A capillary pressure drainage simulation is conducted in a water-wet Berea sandstone sample initially filled with water. When oil invades the pore space as the capillary pressure is increased, a fraction of the pore-grain surface is altered towards an oil-wet condition, as determined by a novel wettability alteration process. This process calculates local curvature at every surface element of the rock, obtains local capillary pressure from the simulation and assumes a disjoining pressure to determine water-film breakage at every location of the pore-grain surface. As a result, a spatially varying rock wettability is created. Using this new wettability distribution, the simulation is continued to allow the fluid phases to redistribute accordingly. The process is iteratively carried out until both fluid saturation and wettability distribution converged at a given applied capillary pressure. Afterwards, the pressure is ramped up to the next stage and the process is repeated again. It has been found that the wettability alteration is a slow dynamic process where the non-wetting phase can gradually invade finer pore space as the surrounding grain wettability is altered. In this study, it has also been found that wettability alteration of the reservoir rock produces lower connate water saturation during primary drainage compared to the simulation results without alteration. The resulting spatially varying wettability distribution from primary drainage is used for a subsequent water flooding simulation to calculate water-oil relative permeability curves. The methodology presented in this work can be leveraged to better understand and predict an improved mixed wetting conditions found in the reservoir rocks which is needed for more accurate displacement tests such as relative permeability simulations.

Evaluation of the impact of low-salinity water on wettability alteration and oil recovery in Berea sandstones

Low-salinity water (LSW) flooding is an emerging technique to enhance oil recovery from carbonate and sandstone reservoirs. Despite growing interest in the field, significant disparities remain regarding the underlying mechanisms. While most researchers agree that wettability alterations may be the dominant mechanism, their quantitative impact on oil recovery remains elusive. This study quantitatively evaluated the effects of LSW flooding on rock wettability alteration and oil recovery enhancement using a non-polar crude through a series of U.S. Bureau of Mines (USBM) tests and contact angle measurements on synthetic clay-free Berea samples with similar textural properties and pore structures. Experimenting on clay-free samples and non-polar crude evaded the effects of (i) mineral dissolution, (ii) interfacial tension reduction due to in-situ saponification, and (iii) wettability alteration due to multi-ion exchange between clays and the crude-oil polar compounds. When water salinity varied from 85,000 to 4,000 ppm, the USBM index increased from approximately 0.26 to 0.38, thereby confirming a minor change in wettability alteration toward a more water-wet condition. These changes were consistent with a decrease in the contact angle from approximately 55.6° to 35.3°. As water salinity decreased to approximately 5 % of its original value, centrifuge data indicated a drop in the residual oil saturation from 0.247 to 0.202, corresponding to a minor increase (of approximately 4 %) in the oil recovery factor at the end of the forced imbibition cycle. This slight oil recovery enhancement is consistent with the minor wettability alterations observed in this study. However, the relatively large recovery factor values reported in the literature were not reproduced in this experiment. The reported findings of this study concerning the evaluation of wettability alteration and recovery factor improvement caused by LSW flooding are unique because they (i) are based on reproducible measurements obtained using state-of-the-art ultrahigh-speed rock centrifuge and core test system that simultaneously measures capillary pressure, evaluates rock wettability, and generates relative permeability data, and (ii) are focused on clean sandstones.

Aging Effect on Rock Wettability Alteration

One of the factors controlling fluid distribution in porous media is wettability, which is ranging from water-wet to oil wet. Wettability could be changed due to the long-time contact with hydrocarbon liquids. Wettability alteration resulting from the aging of core samples in hydrocarbon liquids becomes a widely used technique. The aging of Core samples from different locations in different types of liquids had been studied. The aging periods used in these studies range from hours to 110 days. In this work, synthetic core samples were aged for a period ranging from 205 to 824 days into two different hydrocarbon liquids (heavy crude from the East Baghdad oil field and gas oil). Results show that long time aging periods dramatically alter wettability; also, heavy crude oil alters wettability higher than that of light hydrocarbon.

Quantum mechanics and molecular dynamics strategies to investigate self-aggregation of Quinolin-65

Asphaltene is the heaviest and most polar component of the crude oil. Asphaltene precipitation and deposition results in some adverse processes in both upstream and downstream petroleum industry such as formation of water-in-oil emulsions, wettability alteration of the reservoir rock, pore blockage leading to permeability impairment, blockage of transportation pipeline, and catalyst poisoning in refineries. Asphaltene self-aggregation plays a major role in all these operational difficulties. Although several studies have been carried out on asphaltene aggregation, there is limited scientific understanding of asphaltene self-aggregation at the microscopic level. In this study, Quinolin-65 molecule is considered as a model asphaltene structure. The effect of various factors contributing to self-aggregation of Quinolin-65 molecules including intermolecular interactions, temperature, pressure, solvent, and molecular structure are investigated using quantum mechanics analysis and molecular dynamics (MD) simulations. Results of reduced density gradient (RDG) analysis demonstrated that the strong van der Waals interaction between aromatic rings in two Quinolin-65 molecules is a critical factor in their dimerization and self-aggregation. Radial distribution function, potential of mean force, and mean square displacement are calculated using MD simulation. The Quinolin-65 aggregation tendency in the toluene medium is significantly decreased compared to that in the water and heptane media, due to the interactions between the Quinolin-65 molecules and toluene. According to the MD simulation results, the solubility parameter of the medium can affect the Quinolin-65 aggregation process. The stability of Quinolin-65 molecule in the medium is increased by increasing the temperature. Upon a change in the Quinolin-65 aggregation behavior, the free energy variation range with pressure and temperature is from −4.01 to −0.23 kjmol and −3.49 to −0.56 kjmol, respectively. This study provides new insights/findings to better understand the interaction force(s) between the Quinolin-65 molecules as well as the effect of different thermodynamic conditions on Quinolin-65 molecules self-aggregation at the molecular level. Moreover, this research work assesses the synergistic effects of influential parameters (e.g., thermodynamic conditions, solvent, and structure) on the Quinolin-65 self-aggregation behavior, which can help predict some serious flow assurance issues associated with the precipitation/deposition of asphaltene particles.

A comprehensive study on the application of a natural plant-based surfactant as a chemical enhanced oil recovery (CEOR) agent in the presence of different ions in carbonate reservoirs

Surfactant flooding is a promising CEOR approach in carbonate reservoirs and its efficiency has been verified. Commercial surfactants may impose various health and environmental issues. Therefore, utilizing a natural biodegradable surfactant at a low cost is a valuable option for the petroleum industry. In this research, a non-ionic surfactant derived from Acanthophyllum Plant Root Extract (APRE) was used as a bio-surfactant. The EOR potential of this surfactant was evaluated through various tests. Oil-water system interfacial tension (IFT) measurement, contact angle test for carbonate rock wettability alteration assessment, emulsion stability, compatibility, and surfactant flooding test were conducted. The effect of different ions of various salts on the IFT, carbonate rock wettability and the chemical interactions were also studied. The emulsion stability created by the surfactant was assessed through observational tests. The compatibility test (at 25 °C) showed that negligible sediment below the salinity of 50,000 ppm was formed. The IFT at CMC in formation water (optimum concentration of 12000 ppm) was reduced to 1.06 mN/m from an initial value of 2.16 mN/m. The optimum IFT value at different salinities was also determined. The wettability of the carbonate rock from a strongly oil-wet state (168°) was altered to water-wet (60.3°) in the presence of surfactant and FW with a concertation of 10,000 ppm. In the core flood test, the effect of different slug sizes and soaking time was also determined. It was observed that increasing slug size results in a lower mobility ratio and consequently higher oil recovery.

A novel experimental study on inhibition of asphaltene deposition

Asphaltene as problematic fraction of crude oil is known that is separated from crude oil because of variations in temperature, pressure, and compositions. The deposition of asphaltene causes many problems including tubing blockage and rock wettability alteration, therefore, the study of asphaltene deposition has been highlighted. In the present study, the impacts of various effective parameters and inhibitors on asphaltene deposition rate have been studied. The effect of flow rate and ratio of precipitant to crude oil have been investigated. The SDS, triton x-100, and salicylic acid abilities in reduction of asphaltene deposition have been evaluated by using capillary setup. The experiments show that SDS has the better performance than salicylic acid and triton x-100. Next, the impact of concentration of SDS on rate of deposition has been studied. The obtained results show that increment in concentration of SDS decreases the rate of asphaltene deposition. The current study can be used as a helpful tool for petroleum engineers dealing with asphaltene deposition problems.

Impact of Brine on Disjoining Pressure and Rock Wettability of Oil, Brine, and Mineral Systems

The alteration of rock wettability is essential for improving the efficiency of low-salinity water flooding. However, the fundamental understanding of this process remains unclear. In this paper, an extended Derjguin–Landau–Verwey–Overbeek (DLVO) theoretical model was applied to study the effects of cation types, brine concentrations, and mineral types on rock wettability in an oil–brine system. The zeta potential was measured to analyze the electric double layer. The oil–rock contact angles were tested to evaluate the wettability. The disjoining pressure was also estimated to analyze the rock wettability changes. The divalent cation showed a greater ability to compress the electric double layer. The lower concentrations of cations led to a thicker water film, promoting the detachment of oil from the rock surface. Clay minerals showed a greater impact on the wettability of rocks than quartz. This study improves the fundamental understandings of alteration of wettability in brine, oil, and rock systems and elucidates the mechanisms of disjoining pressure effects on low-salinity water flooding while shedding some light on improving the performance of low-salinity water flooding.

Effects of modified graphene oxide (GO) nanofluid on wettability and IFT changes: Experimental study for EOR applications

The application of nanoparticles (NPs) in enhanced oil recovery (EOR) offers a practical approach to resolving some surface-related problems encountered in contemporary technological processes. In this study, graphene oxide nanosheets (GONs) were synthesized by Hummer's method and, then, were subjected to surface modification by hexamethyldisilazane (HMDS) and diazonium sulfonic (DS) compounds. The new combination was known as GO-Su-HMDS. The potential stability of GO-Su-HMDS nanofluids (NFs) was investigated using the zeta ( ζ ) potential test. A comparative study of the effect of the synthesized NFs on wettability alteration of the reservoir rock was performed using interfacial tension (IFT) and contact angle experiments. According to the results of this study, the contact angle decreased from the initial value of 161° (oil wet) to 35° (water wet). In addition, IFT decreased from 18.45 mN/m for deionized (DI) water to 8.8 mN/m for 500 ppm GO-Su-HMDS NF. Moreover, the results of flooding experiments showed that the NPs of a GO-Su-HMDS concentration of 400 and 500 ppm could increase the oil recovery by 20% and 19%, respectively. The experimental results showed that GO-Su-HMDS NFs with a concentration of 500 ppm have the best efficiency in terms of altering the wettability of the rock from oil wet to water wet. Thus, it can be said that this nanofluid can reduce the contact angle and IFT and also increase the sweeping efficiency of oil.

Experimental Investigation of Reservoir Rock Wettability Alteration by Matricaria Chamomilla Extract

Residual oil can be mobilized by reducing the interfacial tension between oil and water and/or by altering the wettability of the rock through surfactant flooding. Recently natural surfactants have been considered as opposite to synthetic surfactants due to environmental problems associated with synthetic surfactants. This work introduces a plant-based natural surfactant named Matricaria Chamomilla as an agent of reservoir rock wettability alteration. Qualitative and quantitative methods were used to measure rock samples' wettability. For this purpose, flotation wettability, separation wettability, and the pendant drop method were used. The results show that Matricaria Chamomilla extract (MCE) changes the reservoir rock wettability to some degree equivalent to other natural surfactants. The highest wettability variation was observed at 12%wt MCE concentration with 28% change and 21% for critical micelle concentration (CMC) of 5.5%wt.

Wettability Alteration of Carbonate Rock by Chelating Agents and Viscoelastic Surfactants: Synergetic Impact

Wettability Alteration of Carbonate Rock by Chelating Agents and Viscoelastic Surfactants: Synergetic Impact

Application of hybrid low salinity hot water flooding to enhance oil recovery from heavy oil carbonates

The high efficiency of Low Salinity Water (LSW) injection in carbonates, leading to rock wettability alteration from oil-wet to water-wet and, hence, resulting in better oil displacement, has been confirmed by numerous studies. In recent years, the combination of LSW injection with other Enhanced Oil Recovery (EOR) techniques has been widely discussed, to activate the synergistic effects of hybrid EOR methods leading to additional oil recovery. The idea of combining LSW injection with a thermal approach, known as Low Salinity Hot Water (LSHW) injection, is a highly promising hybrid EOR method for heavy oil carbonate formations. In this study, the performance of LSW and hybrid LSHW injection was experimentally evaluated for heavy oil carbonate cores by different measurements of rock-fluid interactions and core flooding experiments. Contact angle measurements were conducted to investigate the optimal dilution of seawater (SW) and evaluate the performance of different variations of Potential Determining Ions (PDIs) concentration on wettability change. Appropriate dilution and ion management was applied to design LSW and engineered water (EW) for oil displacement at different temperatures (from 20 to 70 °C) in order to evaluate the standalone LSW and hybrid LSHW injection performance. The injection of LSW and EW was estimated to be inefficient for heavy oil carbonates, while hybrid LSHW flooding showed a significant increase of oil recovery with the best performance of the brine spiked by PDIs, where 60% and 55% of the residual oil was displaced at 50 °C and 70 °C, respectively. Moreover, the injection of LSHW directly after SW was found to be more practical than following LSW flooding. The application of the hybrid EOR method activates different mechanisms, such as oil detachment from the rock surface, due to the wettability alteration by EW/LSW and viscosity reduction by the thermal methods. Combined active mechanisms result in better performance, compared to the standalone EOR methods. Rock dissolution and multi-ion exchange by PDIs were identified as the main mechanisms of wettability alteration by EW/LSW via the results of ion chromatography analyses. The synergy between EOR methods affects the active mechanisms of LSW/EW flooding. For example, an increase in temperature showed more active multi-ion exchange and rock dissolution, which resulted in higher oil release from the rock surface.

Features of the Early Hydrocarbon Accumulation and Its Effects on the Late Accumulation in Sandstone Reservoir: A Case Study of the Eocene Dongying Depression, Bohai Bay Basin

Multi-stage hydrocarbon generation and accumulation are very common in petroliferous basins. Also, determination of hydrocarbon accumulation stages and each related diagenetic feature is important for understanding the distribution of current oil and gas resources in one individual basin. However, in the case of conventional sandstone reservoirs, few studies have focused on these resulting reservoir features (e.g., physical property and wettability) that are caused by the first accumulation of hydrocarbons and their geological implications. In this study, taking the reservoir from the Eocene Dongying Depression as an example, we investigated the features of the early hydrocarbon accumulation and its effects on the late accumulation, by analyzing the early accumulation-related paragenesis, fluid inclusions, clay minerals content, reservoir physical property, and wettability in sandstones. Our results show that the early stage accumulation of the overpressured hydrocarbon fluid could support and offset some loads of overburden, weaken the normal compaction, and preserve some original pores. Also, the early hydrocarbon accumulation resulted in an alternated, diagenetic fluid environment from the initial acidic to subsequent alkalic conditions, with the overall dissolution intensity stronger than the cementation, and formed a large number of secondary pores. As a result, the early accumulation was beneficial to reservoir space development and provided more space for the late hydrocarbons. In addition, the early hydrocarbon accumulation could cause the alteration of rock wettability and gradually formed a lipophilic migration pathway from the source rock to the reservoir. Also, the late stage of hydrocarbons would preferentially choose this dominant pathway for their migration (i.e., inheritance of migration pathway).

Improving the stability of nanofluids via surface-modified titanium dioxide nanoparticles for wettability alteration of oil-wet carbonate reservoirs

The main challenge of the application of nanofluids for enhanced oil recovery (EOR) in oil-wet carbonate reservoirs is maintaining their stability under high-temperature and high-salinity which is normally seen in reservoir conditions. In this work, surface-modified TiO2 nanoparticles were synthesized by N-(2-Aminoethyl)−3-Aminopropyltrimethoxysilane (AEAPTMS) as a coupling agent for surface modification of nanoparticles. Zeta potential and dynamic light scattering analyses were used to evaluate the stability of the prepared nanofluids. Results indicated that nanofluids had high stability in 90 °C and 20 wt% salinity. The influence of nanofluids on wettability alteration of carbonate rocks was studied by measuring the contact angle value. Untreated rock samples were strongly oil-wet, with water advancing and receding contact angles of 165.1° and 166.2°, respectively. After treatment with 3wt% concentration of surface-modified TiO2 nanoparticles, the rock plate wettability changed to a water-wet state, with water advancing and receding contact angles of 37.6° and 48.2°, respectively. Suggested surface-modified TiO2 nanoparticles were more effective in wettability alteration of the rock surfaces compared to the un-modified TiO2 nanoparticles. Furthermore, higher concentration of nanoparticles, higher the ability of the nanoparticles on changing the rock wettability.

Developing novel bio-nano catalyst well clean up fluid to remove formation damage induced by polymeric water-based drilling fluids

Drilling and completion fluids may cause significant formation damage in oil and gas reservoirs, directly affecting productivity. For many years, operators have applied different stimulation practices such as acidizing, oxidizers, chelating agents, and enzyme treatment to remove formation damage associated with drilling fluids filter cake. An enzyme-based biological treatment was combined with other chemicals or additives as a selective well clean-up practice to improve removing polymer content in the filter cake. However, the secondary formation damage such as deep cleaning of the invaded zone and wettability alteration remained the main concern. This paper presents the development of an innovative clean-up fluid formulation by immobilizing an enzyme and a selective nanoparticle as Bio-Nano Well Clean-Up Fluid (BNWC) in potassium chloride brine to enhance WBM filter cake removal. Several bulk experiments, including; precipitation, iodine test, and viscosity measurement, demonstrate the enzyme's optimization, the nanoparticle concentration, and base fluid brine. BNWC in potassium chloride brine showed the highest HPHT filtration rate at 200 °F and differential pressure of 100 psi and increased the filtration rate by more than 90 percent compared to the conventional enzyme in the same brine. Contact angle measurements confirmed wettability alteration of the carbonate rock to water-wet, and IFT measurements showed higher oil mobility potential. Finally, core flooding tests at reservoir conditions showed a 300 percent enhancement in injection rate and a 50% improvement in core permeability after damage. The immobilization of the enzyme with the nanoparticle has been developed successfully for other applications in bioremediation, farming, and other industries, but the novelty of this research demonstrates the application of nanobiocatalysts in drilling fluids for the first time. This innovative clean-up fluid enhances the enzymatic activity and removes primary and secondary formation damage associated with drilling fluid filter cake.