Natural geochemical data, which refer to the natural ion concentration in produced water, contain important reservoir information, but is seldomly exploited. Some ions were used as conservative tracers to obtain better knowledge of reservoir. However, using only conservative ions can limit the application of geochemical data as most ions are nonconservative and can either interact with formation rock or react with other ions. Besides, mistakenly using nonconservative ion as being conservative may cause unexpected results. In order to further explore the nonconservative natural geochemical information, the interaction between ion and rock matrix is integrated into the reservoir simulator to describe the nonconservative ion transport in porous media. Boron, which is a promising nonconservative ion, is used to demonstrate the application of nonconservative ion. Based on the new model, the boron concentration data together with water production rate and oil production rate are assimilated through ensemble smoother multiple data assimilation (ES-MDA) algorithm to improve the reservoir model. Results indicate that including nonconservative ion data in the history matching process not only yield additional improvement in permeability field, but also can predict the distribution of clay content, which can promote the accuracy of using boron data to determine injection water breakthrough percentage. However, mistakenly regarding nonconservative ion being conservative in the history matching workflow can deteriorate the accuracy of reservoir model.

CO 2 storage and sequestration are regarded as an effective approach to mitigate greenhouse gas emissions. While injecting an enormous amount of CO 2 into carbonate–rich aquifers, CO 2 dissolves in the formation brine under the large pressure, and the subsequently formed CO 2 –enriched brine reacts with the calcite. Reaction–induced changes in pore structure and fracture geometry alter the porosity and permeability, giving rise to concerns of CO 2 storage capacity and security. Especially in the reservoir or aquifer with natural fractures, the fractures provide a highly permeable pathways for fluid flow. This study aims to analyze the acid–rock interaction and subsequent permeability evolution in the systems with complex fracture configurations during CO 2 injection by implementing a pore–scale DBS reactive transport model. The model has been developed by expanding the functionality of OpenFOAM, which is an open–source code for computational fluid dynamics. A series of partial differential equations are discretized by applying the Finite Volume Method (FVM) and sequentially solved. Different fracture configurations in terms of fracture length, density, connection, and mineral components have been considered to investigate their impacts on the dynamic porosity–permeability relationship, dissolution rate, and reactant transport characteristics during CO 2 storage. The investigation revealed several interesting findings. We found that calcium (Ca) concentration was low in the poorly connected area at the initial time. As CO 2 –enriched brine saturated the system and reacted with calcite, Ca started being accumulated in the system. However, Ca barely flowed out of the poor–connected area, and the concentration became high. Lengths of branches mainly influenced the dissolution rates, while they had slight impacts on the porosity–permeability relationship. While fracture connectivity had an apparent influence on the porosity–permeability relationship, it showed a weak relevance on the dissolution rate. These microscopic insights can help enhance the CO 2 sealing capacity and guarantee environmental security.

CO 2 foams have been used for a long time for enhanced oil recovery (EOR) and carbon capture, utilization, and storage. Note that conventional CO 2 foam focuses on mobility control and storage of bare CO 2 . However, this technology has suffered from low storage efficiency and EOR because of foam instability. In this study, the geological storage of CO 2 and coal fly ash (CFA) using Pickering foam for EOR was explored. The aim is to obtain an inexpensive method for EOR and storage of greenhouse gases and atmospheric pollutants. The Pickering foam was prepared using Waring blender method. The experiments were conducted to evaluate CO 2 /liquid interface enhancement by measuring the interfacial tension and interfacial viscoelastic modulus. As per the heterogeneous sandpack flooding experiments, the profile control capacity and the performance of oil displacement using CO 2 foam enhanced by CFA were investigated. The amount of storage from dynamic aspects of CO 2 and CFA was measured to demonstrate the storage law. The stability of aqueous foam was improved significantly after the addition of CFA. The half-life time of foam stabilized by CFA particles increased by more than about 11 times than that of foam without CFA particles. The interfacial dilatational viscoelastic modulus of CO 2 /foaming solution increased with CFA particle concentration increasing, indicating the interface transformed from liquid-like to solid-like. Flooding experiments in heterogeneous porous media showed that more produced fluid was displaced from the relatively low-permeability sandpack after the injection of CO 2 foam with CFA. The oil recovery by CFA stabilized foam was improved by ~28.3% than that of foam without CFA particles. And the sequestration of CO 2 in heterogeneous porous media was enhanced with the addition of CFA to CO 2 foam, and the CFA stabilized foam displayed a strong resistance to water erosion for the storage of CO 2 and CFA. This work introduces a win–win method for EOR and storage of CO 2 and atmospheric pollutant particles. CFA from coal combustion was used as an enhancer for CO 2 foam, which improved the interfacial dilatational viscoelasticity of foam film and the dynamic storage of CO 2 . Furthermore, the storage of CO 2 and CFA contributed to improvement in sweep efficiency, and thus EOR.

The efficiency of CO 2 water-alternating-gas (WAG) flooding is highly limited in low-permeability heavy oil reservoirs due to the viscosifying action of W/O emulsification and high mobility contrast between oil and CO 2 . Here we propose a new enhanced oil recovery (EOR) process which involves water-based nanofluid-alternating-CO 2 (NWAG) injection, and investigate the synergistic effect of nanofluid and CO 2 for enhancing heavy oil recovery. Firstly, the oil-nanofluid and oil-water emulsions were prepared, and the bulk rheology and interfacial properties of emulsion fluid were tested. Then, core flooding tests were conducted to examine the NWAG flooding efficiency and its underlying mechanisms. The results showed that the bulk viscosity and viscoelasticity of oil-nanofluid emulsion reported much lower than those of oil-water emulsion, and nanofluid presented a positive contribution to the phase inversion from W/O to O/W emulsification. Compared with oil-water emulsion, the interfacial storage modulus of oil-nanofluid emulsion was obviously increased, which confirmed that more of crude oil heavy components with surface activity (e.g., resin and asphaltene) were adsorbed on interfacial film with the addition of silica nanoparticles (NPs). However, the interfacial viscosity of oil-nanofluid emulsion was much lower than that of oil-water emulsion, showing the irregularity of interfacial adsorption. This implied that the self-assembly structure of crude oil heavy component of the oil-water interface was destroyed due to the surface activity of silica NPs. During the core flooding experiments, NWAG injection could reduce the displacement pressure by 57.14% and increase oil recovery by 23.31% compared to WAG injection. By comparing produced-oil components after WAG and NWAG injection, we found that more of crude oil light components were extracted by CO 2 during NWAG flooding, showing that the interaction between CO 2 and crude oil was improved after oil-nanofluid emulsification. These findings clearly indicated two main EOR mechanisms of NWAG injection. One was the phase inversion during the nanofluid flooding process. The addition of silica NPs promoted phase-inversion emulsification and thus improved the displacement efficiency. The other was the enhanced interaction between CO 2 and crude oil after oil-nanofluid emulsification. Because of the enhanced adsorption of crude oil heavy component on the oil-water interface, the proportion of light hydrocarbon increased in the bulk phase, and so the interaction between CO 2 and oil phase was improved. This work could provide a new insight into the high-efficiency exploitation of low-permeability heavy oil reservoirs.

Spontaneous imbibition (SI) is an essential method for accelerating mass exchange between fracture and matrix in tight oil reservoirs. However, conventional systems such as brine and surfactant solution have limited imbibition effects, so there is still abundant remaining oil in the matrix. Nanoemulsion holds the most promising potential in improving tight oil recovery owing to the favorable surface activity and nanoscale droplets, but it still lacks economic and facile methods to fabricate nanoemulsions. Therefore, in this paper, we prepared a kind of O/W nanoemulsion of catanionic surfactants with a low dosage of surfactant and energy consumption, which was then used to assess spontaneous imbibition performance in Changqing outcrop cores by experimental and numerical simulation. We have fully considered the possible imbibition mechanisms of nanoemulsion including wettability alteration, IFT reduction, solubilization and emulsification, etc., and successfully applied to the nanoemulsion imbibition model. The model and experimental data were found to be in good agreement. The results showed that the imbibition rate and oil recovery factor of the nanoemulsion in the first 100 hours are lower than that of brine. In the late stage, we observed a longer equilibrium time and a faster and higher oil imbibition process in nanoemulsion with ultralow IFT. Finally, we confirmed that solubilization and emulsification is one of the domiant mechanisms for nanoemulsion imbibition by comparing with the modelling without considering solubilization and emulsification.

Cr 3+ polymer gel flooding technology is very important for enhancing oil recovery and its field trails have obtained significantly oil increment effect. However, its laboratory physical simulation experiments are rarely carried out according to real reservoir conditions. Therefore, it is very important to carry out relevant research work. Aiming at the reservoir condition of Bohai Oilfield (an offshore oilfield in China), the experimental studies on the pore structure characteristics of reservoir on the properties of Cr 3+ polymer gel are carried out. The effect of different core permeability (500, 1500 and 5000 ×10 −3 μm 2 ), clay content (4.5%, 9.0% and 18%), mineral type (kaolinite, montmorillonite and illite), oil saturation (79.2%, 65.4% and 49.3%) and dynamic gelation effect are thoroughly studied. Finally, its application is introduced and analyzed. Research results show that, with the increase of reservoir permeability and pore throat size, the gelation effect improves. Also, the loose cementation degree is helpful for rapid gelation. In additional, with the decrease of the content of clay and oil saturation, the gelforming effect gets better. However, the dynamic gelation strength is very low in porous media. And after chemical injection, suspension of water flooding could promote the gel-forming performance. From the field test results, this technology has obtained good effect in Bohai oilfield, due to the high permeability, severe heterogeneity, loose cementation and high water cut. In conclusion, it is very important to study on the gelation effect under the real reservoir conditions deeply. Therefore, the relevant experimental studies have been carried out comprehensively. And its mechanism are further explored. Furthermore, its field application has also been also summarized, which is vital to the success of this technology.

The microfluidic experiments were conducted in this paper to clarify the flow dynamics of in situ microemulsion and further understand its EOR performances. Two kinds of 2.5D glass micromodel with varied depths of pore and throat are fabricated. One is designed for the imbibition tests, which consists of two fractures and a tight matrix. Another one is a fractured micromodel designed for the flooding tests. The micromodels are originally water wet, and can be altered to oil wet through the surface modification. At the same time, three microemulsion-forming surfactant solutions at the salinity of type I, II or III were prepared, respectively. Then the flow dynamics of these three surfactant solutions during imbibition and flooding process were visualized by the microfluidic experiments. Results show that the type I surfactant solution realizes the highest oil recovery rate in both water-wet and oil-wet imbibition micromodels. Meanwhile, the type III surfactant solution realize the highest oil recovery in both water-wet and oil-wet fractured micromodels.

Carbon dioxide injection into sedimentary formations has been widely used in enhanced oil recovery (EOR) and geological-storage projects. Several field cases have shown an increase in water injectivity during CO 2 Water-Alternating-Gas (WAG) projects. Although there is consensus that the rock-fluid interaction is the main mechanism, modeling this process is still challenging. Our main goal is to validate a physically based model on experimental observations and use the validated model to predict CO 2 injectivity alteration based on geochemical reactions in carbonate rocks. In this paper, we present a new method for CO 2 reactive transport in porous media and its impact on injectivity. We hypothesize that if CO 2 solubilizes in the connate water, then it induces a shift in chemical equilibrium that stimulates mineral dissolution. Consequently, porosity and permeability will increase, and cause alterations to well injectivity. We develop a predictive model to capture this phenomenon and validate the model against available data in the literature. We use UTCOMP-IPhreeqc, which is a fully coupled fluid-flow and geochemical simulator to account for rock/hydrocarbon/water interactions. In addition, we perform several experiments to test CO 2 /water slug sizes, mineralogy assembly, injected brine composition, and gravity segregation combined with the effect of heterogeneity. Coreflood simulations using chemical equilibrium and kinetics indicate mineral dissolution at reservoir conditions. The results suggest that the intensity of rock dissolution depends on formation mineralogy and brine composition as carbonate systems work as buffers. Additionally, we show that prolonged CO 2 and brine injection induces petrophysical alteration close to the injection region. Our field-scale heterogeneous reservoir simulations show that permeability alteration calculated based on Carman-Kozeny correlation and wormhole formulation had the same results. Furthermore, we observed that water injectivity increased by almost 20% during subsequent cycles of CO 2 -WAG. This finding is also supported by the Pre-Salt carbonate field data available in the literature. In the case of continuous CO 2 injection, the carbonate dissolution was considerably less severe in comparison with WAG cases, but injectivity increased due to unfavorable CO 2 mobility. With the inclusion of gravity segregation, we report that the injectivity doubles in magnitude. The simulations show more extensive dissolution at the upper layers of the reservoir, suggesting that preferential paths are the main cause of this phenomenon. The ideas presented in this paper can be utilized to improve history-matching of production data and consequently reduce the uncertainty inherent to CO 2 -EOR and carbon sequestration projects.

Gas reservoirs contain substantial amounts of natural gas and, in some cases, associated high API liquid hydrocarbons. Condensation of heavy hydrocarbons, especially in the area closer to the wellbore, occurs as a direct result of the decline in reservoir pressure. This hydrocarbon condensate, and in some cases water, tends to accumulate in the pore space and form a liquid bank. This liquid bank will result in a reduction in gas relative permeability and overall reduction in the well's productivity. This paper illustrates the synthesis and utilization of surface modified silica nanoparticles to mitigate the liquid banking phenomenon in gas reservoirs. Silica nanoparticles (S-NPs), of different sizes, were synthesized using the Stöber process. The impact of the nanoparticle size and degree of functionalization with different hydrophobic and omniphobic groups on altering the rock wettability properties to mitigate liquid banking in gas reservoirs were studied. The S-NPs (of sizes between 50-400 nm) were functionalized with various linear and branched fluoroalkyl groups, terminal amine, and epoxy groups. The particle size of surface modified silica nanoparticles was determined using dynamic light scattering (DLS). The performance of the surface modified silica nanoparticles was evaluated through measuring surface charge, change in contact angle, and by performing core flow experiments at reservoir conditions. A glass slide dip coated with 135 nm surface modified silica nanoparticles solution derivatized with terminal amine and perfluoroalkyl group provided a contact angle of 120° and 83° with water and decane, respectively. The contact angle can be tailored by changing the amount of amine and perfluoroalkyl concentrations on the particle surfaces. A contact angle of around 90° indicates a nonwetting neutral surface that results in minimizing capillary pressure and enhancing mobility of both hydrocarbon and water liquid phases. Using core flow studies and by estimating the improvement in gas and liquid relative permeabilities, surface modified silica nanoparticles treatment demonstrated a comparable performance to commercially available solutions at 1/5 the treatment volume. The surface modified silica nanoparticles sustained its performance indicating a stable and permanent coating on the rock surface. The silica nanoparticles functionalized with fluoroalkyl group, terminal amine and epoxy can be directly pumped without the need for a pretreatment of the rock surface. This results in less complexity when it comes to the field operation. The dual- functionalized silica nanoparticles were found to be effective in changing the rock surface wettability to neutral or nonwetting, thereby providing a potential solution to liquid banking problem in gas reservoirs.

Replacing oil from small pores of tight oil-wet rocks relies on altering the rock wettability with the injected fracturing fluid. Among different types of wettability-alteration surfactants, the liquid nanofluid has less adsorption loss during transport in the porous media, and can efficiently alter the rock wettability; meanwhile, it can also maintain a certain oil-water interfacial tension driving the water imbibition. In the previous study, the main properties of a Nonionic nanofluid-diluted microemulsion (DME) were evaluated, and the dispersion coefficient and adsorption rate of DME in tight rock under different conditions were quantified. In this study, to more intuitively show the change of wettability of DME to oil-wet rocks in the process of core flooding experiments and the changes of the water invasion front, CT is used to carry out on-line core flooding experiments, scan and calculate the water saturation in time, and compare it with the pressure drop in this process. Besides, the heterogeneity of rock samples is quantified in this paper. The results show that when the DME is used as the fracturing fluid additive, fingering of the water phase is observed at the beginning of the invasion; compared with brine, the fracturing fluid with DME has deeper invasion depth at the same time; the water invasion front gradually becomes uniform when the DME alters the rock wettability and triggers the imbibition; for tight rocks, DME can enter deeper pores and replace more oil because of its dominance. Finally, the selected nanofluids of DME were tested in two horizontal wells in the field, and their flowback fluids were collected and analyzed. The results show that the average droplet size of the flowback fluids in the wells using DME decreases with production time, and the altered wetting ability gradually returns to the level of the injected fracturing fluid. It can be confirmed that DME can migrate within the tight rock, make the rock surface more water-wet and enhance the imbibition capacity of the fracturing fluid, to reduce the reservoir pressure decline rate and increase production.

Inspired by non-covalent enhancement mechanism, we introduced glycinamide-conjugated monomer (NAGA) with dual-amide in one side group to amplify the hydrogen bonding interactions. Via one-step free radical polymerization strategy, we prepared a type of supramolecular thickener based on binary polymer. With NMR, FT-IR and SEM results’ help, we determined that PNAGA-AM system had unique bis-amide structure of glycinamide-conjugated monomer. As a result, the synthesized polymer could generate a much denser structure based on the high-ordered multiple hydrogen bonding with lower molecular weight (Mn = 778,400 g/mol), increasing the strength and stability of the chains. PNAGA-AM system had good thickening and temperature-resistant properties. The thickener viscosity of PNAGA-AM(3.0wt%) had twice as much as that of corresponding PAM system. And the viscosity of the 1.5 wt% solution prepared by PNAGA-AM could maintain 74 mPa·s at 150 °C. Meanwhile, the supramolecular system showed excellent salt resistance and self-healing performance with the non-covalent/hydrogen bonding interactions and physical entanglements. The viscosity of the PNAGA-AM system did not drop but increase in high salinity (≤ 300,000 mg/L salinity), and the maximum viscosity could increase nearly 44 % compared with the initial situation. In addition, the self-healing efficiency was over 100 % at 120 °C. Overall, the fracturing fluid system based on PNAGA-AM system could maintain outstanding rheological properties under extreme conditions and showed brilliant recovery performance, to make up the disadvantages of currently used fracturing fluid. It is expected to mitigate potential fluid issues caused by low water quality, harsh downhole temperatures and high-speed shearing.

Foams were introduced to enhanced oil recovery (EOR) for the purpose of improving sweep efficiency via mitigating gas breakthrough. In prior works, well-defined nanocellulose-based nanofluids, which can well stabilize foam film as a green alternative to reduce the environmental impact, were successfully prepared in our group. However, due to the costly manufacturing process, its field scale application is restricted. In order to further simply the manufacturing process and minimize the cost, in this study, we proposed another family of functional nanocellulose, in which lignin fraction was remained as well as carboxyl groups. The primary objective of the present work is to investigate the synergism between the lignin-nanocellulose (L-NC) and surfactant in foam film stabilization. Particular attention was placed on the relation between the chemical composition of L-NC and its stabilizing effect. Direct measurements of foamability, drainage half-time, foam morphology, foam decay, etc., were performed. The results showed that after the contents of lignin and carboxyl group were well tailored, the resultant L-NC can significantly improve the stability of foam either in the absence or presence of crude oil. The flooding dynamics observed in core plugs indicated that the L-NC stabilized foams could properly migrate in porous media and generated larger flow resistance accross the cores than surfactant-only foam.

Condensate banking is a common problem in tight gas reservoirs because it diminishes the gas relative permeability and reduces the gas production rate significantly. CO 2 injection is a common and very effective solution for condensate removal in tight gas reservoirs. The problem with CO 2 injection is that it is a temporary solution and has to be repeated frequently in the field in addition to the supply limitations of CO 2 in some areas. Also, the infrastructure required at the surface to handle CO 2 injection makes it expensive to apply CO 2 injection for condensate removal. In this paper, a new permanent technique is introduced to remove the condensate by using a thermochemical technique. Two chemicals will be used to generate in-situ CO 2 , nitrogen, steam, heat, and pressure. The reaction of the two chemicals downhole can be triggered either by the reservoir temperature, or a chemical activator. Two chemicals will start reacting and produce all the mentioned reaction products after 24 hrs. of mixing and injection. Also, the reaction can be triggered by a chemical activator and this will shorten the time of reaction. Coreflooding experiments were carried out using actual condensate samples from one of the gas fields. Tight sandstone cores of 0.9 mD permeability were used. The results of this study showed that, the thermochemical reaction products removed the condensate and reduced its viscosity due to the high temperature and the generated gases. The novelty in this paper is the creation of micro-fractures in the tight rock sample due to the in-situ generation of heat and pressure from the thermochemical reaction. These micro-fractures reduced the capillary forces that hold the condensate and enhanced its relative permeability. The creation of micro-fractures and in turn the reduction of the capillary forces can be considered as permanent condensate removal.

Preformed Particle Gel (PPG) is an appropriate solution for conformance control and managing water production in low permeable reservoirs. Rheological behavior evaluation of these deformable particles is a key factor in designing composition to achieve the best conformance control treatment due to the viscoelastic behavior of these particles along with their swelling. The purpose of this paper is to evaluate the network parameters of PPGs through swelling tests, rheology and determining its role in maintaining their structural strength. Several PPG hydrogels were prepared by varying the concentrations of polyacrylamide and Cr(OAc) 3 as copolymer and crosslinker, respectively. The characterization of these hydrogels was performed using Scanning Electron Micrographs (SEM), Electron Dispersion X-ray analysis (EDX), Environmental Scanning Electron Microscopy (ESEM), ThermoGravimetric Analysis (TGA), and Differential ThermoGravimetry (DTG). The correlation between reaction conditions and network parameters of polymer networks such as, molecular weight of the polymer chain between two neighboring crosslinks, crosslink density, and size fraction have been determined. The swelling of the hydrogels was found through the Fickian diffusion mechanism. In this case, the diffusion rate of water in the 3D structure of the hydrogel is less than the relaxation of the polymeric chain, resulting in a significant increase in the PPG particles volume. As PPG was invaded such as in the reservoir by formation water or oil, repeatedly, the sensitivity factor was measured to ensure the swelling in the electrolyte solution. Based on rheological tests, the dynamic modulus of the swelled PPG was strongly dependent on the concentration and consequently network parameters. Also, through the optimization of the network parameters, the appropriate composition from the point of view of strength (complex modulus of 4×10 4 Pa) and salt sensitivity of 0.5 was presented. In addition, the results of the TGA/DTG test demonstrated the thermal stability of the sample was in temperature range 245 to 340°C. The determination and analysis of the network parameter is the novel technique for predicting the hydrogel performance in porous media and investigating its strength under harsh reservoir conditions. In other words, determination of the network parameter can be a shortcut to ensure the success of the gel performance in porous media.

Recent times have seen an advancement in the area of carbonate acidizing, moving forward from single-phase to two-phase analyses, in an effort to account for the presence of the oil-phase during stimulation treatments. Yet, a lack of a complete capability to understand this complex subsurface process still exists. Characterizing the effect of CO 2 (carbon dioxide), a byproduct of the chemical reaction between carbonates & HCl (hydrochloric acid) has been ignored till date, under the pretext of using high pore pressures to keep CO 2 dissolved in surrounding solution. The presence of CO 2 in porous media changes the dynamics of fluid flow. A three-phase two-scale simulation model is described toward the purpose of accurately modeling the physics of carbonate acidizing. A validation of the model, is conducted using published literature experiments and conducted laboratory corefloods in the area of carbonate acidizing. The acid efficiency curve for a single phase scenario from literature is matched, with the effects of the evolved CO 2 being modeled. Two Indiana limestone core, 6 in. by length and 1.5 in. by diameter, are used for the purpose of a tracer injection study using 5 wt% KCl (potassium chloride) solution, and acid injection study using 15 wt% HCl solution. The experiments were conducted at 71.6°F, and 1,180 psi pore pressures. The Indiana limestone cores are characterized via CT (computed tomography) scans, and a detailed, accurate porosity profile of the core is used as input to the simulation model. The tracer fluid was used to characterize the porous environment and effective dispersion coefficients, and for subsequent calibration of the simulation model. From the conducted single phase acidizing coreflood, the experimental parameters such as pressure drop curves are closely monitored to assess acid breakthrough, and the effluents from the acid coreflood are analyzed for determining the concentrations of CaCl 2 (calcium chloride) and HCl with time. CT scans of the core post acidizing describes the wormhole pattern. These parameters are accurately matched using the simulation model, and subsequent sensitivity studies with the presence of oil are performed thereof. The modeling of CO 2 as a separate phase for mimicking the acid coreflood played a major role in acquiring a better match with all experimental parameters, with limited dependency on empirical pore-scale parameters. It is shown that the rock-wettability for an oil-water system has a large degree of influence on the acid PVbt (pore volumes of acid required to breakthrough), with oil-wet systems requiring higher volumes. An approximate of 30% recovery of the residual oil in place is predicted, purely based on capability of the evolved CO 2 to swell the surrounding oil.

Severe formation damage is induced by the invasion of working fluid and the subsequent water blocking. Surface modification by surfactant adsorption can change the wettability of the rock surface to enhance the removal efficiency of reservoir fluid and reduce the water blockage damage. Therefore, surfactant shows a good potential applicant in condense reservoir. In the current paper, an oligomeric silicone surfactant (OSSF) containing sulfonic acid groups is synthesized to improve the water flowback effect. The critical micelle concentration (CMC) is determined by equilibrium surface tension. Micelle can be formed above the CMC and its size and distribution increase with the concentration. At the same time, the surface tension increases with the aging temperature but decreases with the adding of inorganic salt. The OSSF adsorption through solid-liquid surface can change the surface chemical composition and transfer the wettability of reservoir from water-wet to gas-wet by decreasing the surface energy. Increasing temperature leads to the change in the adsorption isotherm from Langmuir type (L-type) to "double plateau" type (LS- type). Quantum chemistry study shows that the adsorbed layer of OSSF can reduce the adhesive force of CH 4 and H 2 O on the pore surface of cores. The OSSF can also decease the initial foaming volume and stability in induction period and accelerating period of sodium dodecyl benzene sulfonate (SDBS). It is found that the surface tension of OSSF increases with aging temperature but decreases with the adding of inorganic salts.The OSSF has positive effect on wettability reversal to water-wet reservoir by adsorption on solid-liquid interface. The results indicate OSSF adsorption layer can change surface chemical composition and exhibit lower interface energy than that of the cores. The presence of NaCl can decrease foaming volume and improve foam stability of OSSF. At the same time, OSSF can decease the initial foaming volume and stability in induction period and accelerating period of sodium dodecyl benzene sulfonate (SDBS).

Adsorption of surfactant onto rock surfaces is dependent upon a number of factors, including characteristics of both the adsorbent and surfactant molecules. Considering that surfactant-based unconventional means to improve oil recovery are strongly dependent on the interaction at the liquid/liquid interface between soluble surfactant solution and crude oil, loss of surfactant to liquid/solid interfaces can create a negative effect for some of these applications in terms of performance and economics. This study; therefore, focuses on investigating the adsorption mechanism of surfactants onto sandstone and limestone reservoir media. Besides quantifying how much surfactant is adsorbed, emphasis specifically on the effect of surfactant parameters on the adsorption capacity was evaluated. Although literature well documents that mineralogy, temperature, pH, inclusion of other chemicals, and salinity all play strong roles on the adsorption capacity of surfactants on a solid surface; all of these parameters, with exception of mineralogy, were maintained as constants for this work. Anionic alcohol propoxy sulfate, nonionic alcohol ethoxylate, and ether carboxylate surfactants were studied. Academic focus for this effort was placed on surfactant parameters being evaluated including the structure of the surfactant hydrophilic head group and the surfactant hydrophobic tail. The number of mechanisms involved in surfactant loss from aqueous solutions to assorted porous media adds to the complexity of this phenomenon. Experimental results show that various surfactant parameters affect the adsorption differently based on their interaction with different adsorbents. An increase in hydrophobicity appears to increase surfactant adsorption. This was observed through a number of different mechanisms including increasing percent of propylene oxide (PO) and increasing degree of hydrophobe branching of the surfactants. Conversely, increasing carbon chain length and keeping the percent of PO more constant appeared to show a general decrease in adsorption trend with alcohol propoxy sulfate and a discernible decrease in adsorption in sandstone versus limestone mineralogy. It was also observed that varying ratios of propylene oxide and ethylene oxide extensions to alcohol alkoxy sulfate molecules will have an influence on surfactant adsorption. Surfactant properties provide information on the type and mechanism of interactions involving surfactant molecules at the solid/liquid interface and their efficiency as surface-active agents. The findings from this study can be used to improve understanding on how the role of different surfactant parameters may affect surfactant adsorption. This will help lead to enhancements in designing surfactant molecular structures that in turn minimize adsorption to rock surfaces, while maintaining desired fluid performance for effective oil recovery.

A new class of permanent clay stabilizers has been developed inorganic based on an aluminum/zirconium-based compound. The increased charge density of the molecule allows it to bind more strongly to swelling clays, while its relatively low molecular weight allows it to stabilize the clay permanently without causing formation damage by blocking the pore throats and reducing permeability. The most commonly used clay stabilizers are organic and inorganic chloride salts including trimethylammonium chloride, potassium chloride, and choline chloride. These salts have been used for years, are effective in most wells, and are both cheap and abundant. However, their high water solubility and the relatively small size of the cation means that these products are highly mobile and thus are quickly washed away during flowback. Several chemical derivatives were made from a tri-functional amine by reacting it with organic and inorganic acids such HCl, acetic acid, and formic acid; as well as alkylating agents, including chloromethane, benzyl chloride, diethyl sulfate, and paraformaldehyde. Certain cationic polymers have also proven useful as clay stabilizers. These much larger molecules are not as easily washed away due to steric hindrance and a much higher charge density per molecule. These products have proved useful as long-term clay stabilizers, but their high molecular weights can lead to formation damage by causing them to be filtered out on the rock face. In this research, several laboratory tests were carried out on the new clay stabilizer. These tests included coreflood experiments conducted on Berea sandstone cores to assess the stabilizer at high temperatures and the influence of different acids on its performance. Coreflood effluent samples were analyzed using inductively coupled plasma optical emission spectrometry (ICP-OES) to measure the concentrations of aluminum and zirconium. This new permanent clay stabilizer improved productivity from formations that have high clay content by minimizing clay swelling and thus preventing formation damage caused by clogged pore throats and subsequent loss of permeability. It worked well at temperatures up to 250°F and with 15 wt% HCl and regular mud acid (12 wt% HCl, 3 wt% HF).

Acid stimulation in sandstone reservoirs containing significant amount of clays can end up with undesired results due to unexpected reactions between stimulation fluids and formation clays. This paper demonstrates how heavily damaged clay-rich sandstone reservoir completed with cased hole gravel pack (CHGP) in offshore Myanmar can be successfully established for commercial production with organic clay acid stimulation treatment. The formation is laminated dirty sand with very high clay content (up to 30%) and large gross height (>100m MD). Production logging results showed only a small portion of perforated intervals contributing to production. Thus, an appropriate stimulation treatment is required to unlock well potential and prevent screen failures from concentrated flow through a small interval. Given high clay content as well as presence of acid sensitive clays, conventional treatments using HCl as preflush and hydrofluoric (HF) acids as main fluids would result in potential damages from secondary and tertiary reactions. Furthermore, undissolved clays in the critical matrix left over from the treatment would potentially migrate and plug the pore throat. The new acid system was designed to generate small amount of HF in-situ (∼0.1%) at any given time with total strength of 1% HF, which would greatly minimize second and tertiary reactions and also permits acids travel deeper into the formation. Furthermore, the reaction products would react with the clays and physically "welding" the undissolved clays to the surface of the pore spaces permanently and prevent them from migration. The treatment was designed in three stages: 1) screen and gravel pack cleanup using coiled tubing (CT) jetting; 2) injectivity test; 3) main treatment consisting of acetic acids as preflush, and new acid system as main fluids followed by overflush. A newly designed linear gel containing relative permeability modifier was used for diversions. Two underperforming CHGP wells were treated, and both wells yielded 100% increase in productivity with no fine production observed at the surface. The success of the campaign owes to the sophisticated engineering workflow which starts from diagnostic of the damage zone and root-cause of the formation damage, followed by detailed analysis of various skin components using radial numerical reservoir modeling for all the reservoir layers that led to a proper treatment strategy and fluid design based on the damage and formation mineralogy as well as comprehensive laboratory tests. This has helped to minimize the risk of the treatment and eventually unlocked the production from the heavily damaged sandstone reservoir.

Surfactant EOR received attraction due to its extreme capability to increase displacement efficiency by altering the wettability, lowering the oil/water interfacial tension and ultimately mobilizing the residual oil. However, surfactant systems are widely acknowledged to have large adsorption on rock/clay/sediment solid surfaces, which may result in concentration loss, thus impair the effectiveness of the chemical solution and turn the process into an economically unfeasible case. Surfactant adsorption can be affected by the adsorbents, surfactant structure, experimental temperature and some other factors. Also, the driving force for adsorption varies with different surfactants types. Generally speaking, electrostatic interaction is more prominent for those anionic surfactants, while hydrophobic interaction is more common for nonionic type. In this paper, the static adsorption behaviors of two surfactants (A1 and N1) on Bakken minerals and Berea sandstone in high salinity and high temperature Bakken conditions (salinity≈290,000 mg/L, temperature=80~105 °C) were studied using spectrometric iodine method, where 0.1 mM I 2 -0.2 mM KI solution was used as a color developing agent. The primary stability indicated that both surfactants have high compatibility with the Bakken formation brine at high temperature, and their critical micelle concentrations showed a small decrease in the presence of high saline brine. Bakken mineral is relatively complicate, which is composed of quartz, dolomite, calcite and clay, while Berea sandstone contains over 75 wt% quartz. Herein, the effects of surfactant concentration, surfactant type, temperature, adsorbents and salinity on adsorption density were covered, and the impacts of surfactant concentration and adsorbents were found to be more significant. Due to the higher specific surface area and high clay content of Bakken minerals, both anionic surfactant blend A1 and nonionic surfactant blend N1 have pretty high adsorption on Bakken minerals, and the specific adsorption densities of 1000 mg/L surfactant solution were calculated to be 1.74 mg/m 2 and 1.69 mg/m 2 , respectively. Meanwhile, the results also indicated that though the applied surfactant concentration is relatively low, the concentration loss due to adsorption should never be overlooked. Future study on how to effectively reduce the adsorption of surfactant especially in those clay-rich formations is of great significance.