Low-permeability Cores Research Articles

Experimental Research on the Optimization and Evaluation of the Polymer/Chromium-Ion Deep Profile Control System for the Fractured Low-Permeability Reservoirs

The matrix/fracture conductivity of a fractured low-permeability reservoir is variable, and its heterogeneity is serious. When carrying out deep profile control measures, it is difficult to inject under the premise of ensuring the plugging effect. According to the characteristics of the fractured low-permeability reservoir in Chaoyanggou Oilfield, the polymer/chromium ion deep profile control system was optimized via a viscosity evaluation experiment, liquidity experiment and oil displacement experiment. The experimental results show that the high molecular weight main agent/low concentration system and low molecular weight main agent/high concentration system can meet the gel strength requirement. The evaluation results of the injection ability and plugging performance of the fractured low-permeability core show that a high molecular weight profile control system is difficult to inject, while a low molecular weight profile control system has a poor plugging performance and high cost after simulated shear. Therefore, the formulation of the profile control system was determined to be a polymer with a molecular weight of 16 million g·mol−1 as the main agent with a concentration of 1000–1500 mg·L−1. As assisting agents, the concentrations of thiourea, NaCl and NaHCO3 were 900 mg·L−1, 800 mg·L−1 and 700 mg·L−1, respectively. The plugging rate of the system was 87.6%, and the resistance coefficient was 19.2. Finally, a fractured low-permeability core model with parallel long cores was designed, and the optimal profile control system was used for the core oil-displacement experiment. Compared with the water-flooding experiment, the plugging rate can be increased by 6.9–8.0%.

Modified Fe3O4 nanoparticle used for stabilizing foam flooding for enhanced oil recovery

Nanoparticle stabilized foam flooding is a new rising technology of enhanced oil recovery (EOR) which could be applied to produce more crude oil from low permeability reservoirs, but it is still in lab-scale studies. In this paper, Fe3O4 nanoparticles were selected and grafted 1,2-epoxy dodecane for increasing the hydrophobicity of particles’ surface and then characterized by FTIR, TGA and TEM. The samples with four different contact angles (12.7°, 20.6°, 57.5° and 94.3°) were chosen to prepare surface unmodified and modified Fe3O4/sodium dodecyl sulfate/polyacrylamide ((M)Fe3O4/SDS/HPAM) foam dispersion systems and compared their static foam stability. The results showed that the modification on the surface of nanoparticles method could prolong foam half-time of Fe3O4 stabilized foam system. The foam half-time of the system stabilized by the modified Fe3O4 nanoparticles with the contact angle of 94.3° was 2.36 times higher than that of unmodified ones. The core flooding experiments were conducted with the low permeability core samples (< 10 mD)saturated with Dagang crude oil at 80 ℃, 18 MPa, and the results indicated that CO2 foam stabilized by modified Fe3O4 with the contact angle of 94.3° could result in a higher oil recovery rate of 10.64 % OOIP after water flooding. It can be concluded that the modified Fe3O4 nanoparticle stabilizing CO2 foam system could be a promising tertiary oil recovery method for low permeability reservoirs.

Study on frequency optimization and mechanism of ultrasonic waves assisting water flooding in low-permeability reservoirs

Water flooding is one of widely used technique to improve oil recovery from conventional reservoirs, but its performance in low-permeability reservoirs is barely satisfactory. Besides adding chemical agents, ultrasonic wave is an effective and environmental-friendly strategy to assist in water flooding for enhanced oil recovery (EOR) in unconventional reservoirs. The acoustic frequency plays a dominating role in the EOR performance of ultrasonic wave and is usually optimized through a series of time-consuming laboratory experiments. Hence, this study proposes an unsupervised learning method to group low-permeability cores in terms of permeability, porosity and wettability. This grouping algorithm succeeds to classify the 100 natural cores adopted in this study into five categories and the water flooding experiment certificates the accuracy and reliability of the clustering results. It is proved that ultrasonic waves can further improve the oil recovery yielded by water-flooding, especially in the oil-wet and weakly water-wet low-permeability cores. Furthermore, we investigated the EOR mechanism of ultrasonic waves in the low-permeability reservoir via scanning electron microscope observation, infrared characterization, interfacial tension and oil viscosity measurement. Although ultrasonic waves cannot ameliorate the components of light oil as dramatically as those of heavy oil, such compound changes still contribute to the oil viscosity and oil-water interfacial tension reductions. More importantly, ultrasonic waves may modify the micromorphology of low-permeability cores and improve the pore connectivity.

Preparation of CO2 responsive nanocellulose gel for mobility control in enhanced oil recovery

The carbon dioxide (CO2) injection is the promising enhanced oil recovery technique used in low permeability reservoirs. The presence of high permeability fractures along the matrix leads to poor sweep efficiency and gas channeling effect. The CO2 responsive mobility control gels could be a potential solution to mitigate the gas channeling effects. This work showcases the straightforward method to prepare a CO2 responsive gel by mixing aqueous suspension of nanocellulose and ethylenediamine. The addition of CO2 leads to protonation of amine which enhances the ionic strength of the solution. This promotes the agglomeration of nanocellulose to form gel. The rheological properties of the gel were studied and found to have interesting mechanical property. And the micromodel is used to visualize the mobility control phenomenon of the as prepared gel. The core flooding experiment proves that the synthesized gels were effective in low permeable cores.

Application of Well Pattern Adjustment for Offshore Polymer Flooding Oilfield: a Macro-Scale and Micro-Scale Study

The early polymer flooding development technology has been applied to the Bohai Bay oilfield. However, about 50% of the residual crude oil remains in the formation after polymer flooding. The ways to improve the effect of polymer flooding needs to be further investigated. In this paper, we simulated the development effect of well pattern adjustment technology during polymer flooding through laboratory experiments and analyzed the development effect of oil displacement and the distribution of remaining oil from macroscopic and microscopic aspects. The micro-electrode technology was applied to the macro-scale physics experiment to study the development effect and residual oil distribution. In this experiment, nine-spot injection pattern was changed to line-drive pattern during polymer flooding. The micro-scale physics experiment uses nuclear magnetic resonance technology to study the micro-scale distribution of residual oil in the high and low permeability core pores before and after polymer flooding. The experimental results show that in heterogeneous reservoir, the remaining oil is mainly concentrated in the large pores of the medium and low permeability layers at high water cut stage. During the polymer flooding stage, the polymer is squeezed into the large and medium pores of the high-permeability layer and small pores of the low-permeability layer, effectively increasing the sweeping area and displacement efficiency of the low-permeability layer. The residual oil remains mainly in the large pores of the medium and few permeability layers. During the subsequent water flooding stage, the medium permeability layer demonstrates the strongest displacement effect. The increase in yield of the low permeability layer was mainly due to the displacement of oil in the large pores in low permeability layer. After long-term water injection development, the oil recovery of large pores in the low-permeability layer is similar to that in the high-permeability layer. The remaining oil is concentrated in the small pores of the high-permeability layer and the medium and small pores of the low-permeability fiver. The low-permeability layer still has potential for development. Changing the well pattern system is conducted to provide uniform displacement of polymer solution, improving and enhancing the displacement effect of polymer flooding and subsequent water flooding, especially improving the displacement effect in the low permeability layer. In this experiment, the oil recovery of well pattern adjustment was increased by 4.77%. Through experimental research, we believe that polymer flooding with well pattern adjustment can not only expand the flow area by changing the flow field, but also further play the role of polymer profile control. The two mechanisms complement each other, 'effectively improving the unevenness of displacement and enhancing the oil recovery. The experimental results can provide new ideas and technical support for further improving the development effect of polymer flooding in offshore oilfields.

Application of Low-Salinity Waterflooding in Carbonate Cores: A Geochemical Modeling Study

Waterflooding is the most widely applied improved oil recovery technique. Recently, there has been growing interest in the chemistry and ionic composition of the injected water. Low-salinity waterflooding (LSWF) is a relatively recent enhanced oil recovery technique that has the ability to alter the crude oil/brine/rock interactions and improve oil recovery in both clastics and carbonates. In this paper, the increase in the recovery factor during LSWF was modeled based on the exchange of divalent cations (Ca2+ and Mg2+) between the aqueous phase and the carbonate rock surface. Numerical simulations were performed using laboratory coreflood data, and oil recovery and pressure drop from experimental works were successfully history matched. The ion exchange equivalent fractions, effluent ions concentrations, changes in mineral moles, and pH have also been examined. Besides, an investigation of multi-component ionic exchange as a mechanism responsible for wettability alteration during LSWF in heterogeneous low-permeability carbonate cores is presented. The results show that wettability alteration is responsible for the increase in oil recovery during LSWF, as reflected by the shift in the crossover points of the relative permeability curves. A sensitivity study done on many key parameters (e.g., timing of LSWF injection, injection rate and temperature) and the mechanistic modeling method revealed that they all have huge effects on the process.

The Experimental Investigation of the Development Potential of Low-Permeability Reservoirs in the Daqing Oilfield

It is very risky and difficult to develop low-permeability reservoirs, but reservoir development can be guided by the development potential of different low-permeability reservoirs. In this study, natural cores of the Daqing Oilfield were used as the research objects. The throat radius distributions of the different low-permeability cores were determined by the constant velocity mercury injection method, the movable fluid distribution characteristics were determined by nuclear magnetic resonance, and the nonlinear fluid flow characteristics were analyzed via fluid flow experimentation. From these data, the development potential for low-permeability reservoirs was determined. The results show that when the permeability is 1×10−3 μm2, the average throat radius is only approximately 0.9 μm and throats with radii less than 0.1 μm account for approximately 30% of the throats. The throats with an average radius less than 1 μm, especially throats with radii less than 0.1 μm, are the main factor restricting the fluid flow in these cores. The movable fluid is only approximately 20% of the fluid in a core, and the threshold pressure gradient reaches 0.15 MPa/m when the permeability is 1×10−3 μm2, indicating that it is more difficult to develop reservoirs with permeabilities less than 1×10−3 μm2.

Transport of Associative Polymers in Low-Permeability Carbonates

Carbonate reservoirs are heterogeneous from pore scale to field scale. Waterflood in carbonate reservoirs often leaves behind a substantial amount of oil due to pore-scale and large-scale bypassing. Polymer flooding can improve sweep efficiency and oil production. Most EOR polymers cannot be transported through low-permeability (< 30 mD) rocks. Hydrophobically modified associative polymers (APs) associate with each other during passage through pore throats and give a larger flow resistance than conventional polymers (Flopaam) of the same molecular weight. The goal of this work is to investigate the transport of associative polymers in low-permeability carbonate reservoirs (less than 50 md). An associative polymer similar in molecular weight to Flopaam 3330 was investigated in this study. Polymer rheology and the effect of salinity were studied at 60 °C. Mechanical shearing and aggressive filtration were used to modify the particle size distribution in polymeric solutions and improve transport through tight cores. Single-phase polymer transport experiments were performed in outcrop Edwards Yellow and Indiana limestone cores. Mechanical shear degradation reduced the particle size and improved the transport of the associative polymer in low-permeability carbonate cores. The permeability reduction factor and the residual resistance factor were higher for the sheared AP polymers than those for the sheared Flopaam polymer. The resistance factors for the associative polymer were higher than those for Flopaam for a given shear viscosity. Coreflood experiments with AP showed the evidence of two propagation fronts: polymer concentration front and pressure gradient stabilization front due to polymer network formation and polymer adsorption. As AP polymer concentration increased, permeability reduction factor, resistance factor, residual resistance factor and polymer adsorption increased. All the coreflood experiments suggest successful polymer transport in low-permeability carbonate cores even at significantly high polymer concentrations with pre-shearing.

Fuzzy-ball fluid self-selective profile control for enhanced oil recovery in heterogeneous reservoirs: The techniques and the mechanisms

Conventional water flooding and polymer flooding are common approaches to improve oil recovery. However, flooding agents injected into heterogeneous reservoirs preferentially enter the seepage channels in high-permeability zones. As a result, it is difficult to displace the hydrocarbons in low-permeability areas. Therefore, using the agents with selective plugging capability to block the high-permeability channels and promote the subsequent displacement in the low-permeability area has become a potentially preferable solution for enhanced oil recovery (EOR) in heterogeneous reservoirs. In this study, the techniques and mechanisms of the novel fuzzy-ball fluid for enhancing oil recovery in heterogeneous reservoirs are discussed. Laboratory tests were conducted using 45 mm × 45 mm × 300 mm artificial cores with permeability ranging from 200 to 1200 mD to simulate the formation channels. Two cores with different permeabilities were connected in parallel to simulate the heterogeneous formations. The oil displacement performance of fuzzy-ball fluid was compared with that of polymer and surfactant fluids. Flooding the cores with fuzzy-ball fluid could significantly increase the oil recovery rate of the low-permeability cores. Field tests were conducted in two polymer injection wells located in a heterogeneous conglomerate reservoir in Karamay Oilfield, China. After fuzzy-ball fluid flooding, the average daily liquid production rate decreased, the average daily oil production rate increased and the overall water content decreased. There was a significant improvement in oil displacement effect in low-permeability areas.

Novel Spherical Polymer Sealing Agent for Oil-Based Drilling Fluids to Overcome Borehole Instability Problem in Low Permeability Reservoirs

Due to borehole instability problem in low permeability formations, a new type of spherical polymer sealing agent (OLBS) for oil-based drilling fluids was prepared via suspension polymerization, and the sealing effect of polymer sealing agent on low permeability cores was evaluated. The results indicated that OLBS had no influence on the rheological properties of oil-based drilling fluids. The core displacement experiments indicated that OLBS could reduce the core permeability by a significant amount, and thus stop fluid invasion into the formations, so OLBS could provide an excellent sealing effect and improve wellbore strength. Using this polymer sealing agent to plug the low permeability formations is a very powerful approach to address borehole instability problem in troublesome low permeability formations. This sealing agent is suitable for the drilling of long sections of horizontal laterals. In the future, the oil-based drilling fluids containing OLBS might hold great promise to resolve borehole instability problem in low permeability formations.

Optimal analysis of material ratio for artificial rock by 3D printing technique

ABSTRACT Rock cores are important for rock properties research because they are linked to significant oil and gas drilling and production technology around the world. The goal of synthesising rock cores in the laboratory is to simulate the main factors of properties of reservoir rocks such as permeability, porosity and pore radius that can be used for tests in extreme conditions in replacement the high cost of obtaining natural cores. The reproduction of artificial rock cores in the laboratory also enables researchers to obtain samples with predetermined characteristics to better understand the relationship between their physical characteristics. In this paper, low-permeability and high-porosity artificial rock cores were made by 3D printing technology. The behaviour of the main petrophysical characteristics of these samples was investigated, such as setting time, rheology, permeability, porosity and compressive strength. The results were compared with natural samples and showed a high similarity to the petrophysical behaviour. By optimising the ratio of 3D printing materials, the physical properties of the samples were closer to the natural carbonate rocks. It provides a new technique and method to the development of special reservoir physical simulation experiments.

Explicit tracking of CO2-flow at the core scale using micro-Positron Emission Tomography (μPET)

Safe subsurface sequestration of carbon dioxide (CO2) is becoming increasingly important to meet climate goals and curb atmospheric CO2 concentrations. The world-wide CO2 storage capacity in carbonate formations is significant; within deep, saline aquifers and through several CO2-enhanced oil recovery projects, with associated CO2 storage. Carbonates are complex, both in terms of heterogeneity and reactivity, and improved core scale and sub core-scale analysis of CO2 flow phenomena is necessary input to simulators, aiming to establish large-scale behavior. This paper presents a recent advancement in in-situ imaging of CO2 flow, utilizing high-resolution micro-Positron Emission Tomography and radioactive tracer [11C]arbon dioxide to explicitly track CO2 during dynamic flow and subsequent trapping at the core scale. Unsteady state water injection (imbibition) and CO2 injection (drainage) were performed in a low-permeable chalk core at elevated pressure conditions. Short-lived radioisotopes were used to label water and CO2, respectively, and facilitated explicit tracking of each phase separately during single phase injection. Local flow patterns and dynamic spatial fluid saturations were determined from in-situ imaging during each experimental step. Initial miscible displacement revealed displacement heterogeneities in the chalk core, and dynamic image data was used to disclose and quantify local permeability variations. Radial permeability variations influenced subsequent flow patterns, where CO2 predominantly flooded the higher-permeability outer part of the core, leaving a higher water saturation in the inner core volume. Injection of water after CO2 flooding is proposed to be the most rapid and effective way to ensure safe storage, by promoting capillary trapping of CO2. PET imaging showed that presence of CO2 reduced the flow of water in higher-permeability areas, improving sweep efficiency and promoting a nearly ideal core-scale displacement. Alternate injections of water and gas is also expected to improve sweep efficiency and contribute to improved oil recovery and CO2 storage on larger scales. Sub-core analysis showed that residually trapped CO2 was evenly distributed in the chalk core, occupying 40% of the pore volume after ended water injection. Micro-Positron Emission Tomography yielded excellent small-scale resolution of both water and CO2 flow, and may contribute to unlocking fluid flow dynamics and determining mechanisms on the millimeter scale; presenting a unique opportunity in experimental core-scale evaluations of CO2 storage and security.

Experimental Study on the Effect of ASP Flooding on Improving Oil Recovery in Low Permeability Reservoirs Based on a Partial Quality Tool

In order to solve the problem of the poor oil displacement effect of high molecular weight alkali/surfactant/polymer (ASP) solution in low permeability reservoirs, Daqing Oilfield uses a partial quality tool to improve the oil displacement effect in low permeability reservoirs. In the formation, the partial quality tool degrades the polymer through active shearing action, reducing the molecular weight of the polymer, to improve the matching degree to the low permeability oil layer and the oil recovery. In order to study the ability of the partial quality tool to improve the oil displacement effect, the matching degree of high molecular weight ASP solution to low permeability cores is studied, and the ability of quality control tools to change the molecular weight is studied. Then, experimental research on the pressure and oil displacement effect of high molecular weight ASP solution before and after the actions of the partial quality tool is carried out. The results show that ASP solutions with molecular weights of 1900 × 104 and 2500 × 104 have a poor oil displacement effect in low permeability reservoirs. After the action of the partial quality tool, the injection pressure is reduced by 5.22 MPa, and the oil recovery is increased by 7.79%. The injection pressure of the ASP solution after shearing by the partial quality tool is lower than that of the ASP solution with the same molecular weight and concentration without shearing, but the oil recovery is lower. On the whole, the use of the partial quality tool can obviously improve the oil displacement effect in low permeability reservoirs.

Relative Permeability Characteristics During Carbon Capture and Sequestration Process in Low-Permeable Reservoirs.

The injection of carbon dioxide (CO2) in low-permeable reservoirs can not only mitigate the greenhouse effect on the environment, but also enhance oil and gas recovery (EOR). For numerical simulation work of this process, relative permeability can help predict the capacity for the flow of CO2 throughout the life of the reservoir, and reflect the changes induced by the injected CO2. In this paper, the experimental methods and empirical correlations to determine relative permeability are reviewed and discussed. Specifically, for a low-permeable reservoir in China, a core displacement experiment is performed for both natural and artificial low-permeable cores to study the relative permeability characteristics. The results show that for immiscible CO2 flooding, when considering the threshold pressure and gas slippage, the relative permeability decreases to some extent, and the relative permeability of oil/water does not reduce as much as that of CO2. In miscible flooding, the curves have different shapes for cores with a different permeability. By comparing the relative permeability curves under immiscible and miscible CO2 flooding, it is found that the two-phase span of miscible flooding is wider, and the relative permeability at the gas endpoint becomes larger.

ВЛИЯНИЕ ФИЛЬТРАЦИОННО-ЕМКОСТНЫХ СВОЙСТВ ПРИЗАБОЙНОЙ ЗОНЫ ПЛАСТА НА ЭФФЕКТИВНОСТЬ КИСЛОТНОЙ ОБРАБОТКИ

Актуальность. В настоящее время большой объем исследований по оптимизации интенсификации работы скважин связан с изучением влияния скорости закачки кислотных составов на характер образования каналов и определение оптимальных объемов закачки. Важным фактором является первоначальное состояние призабойной зоны скважины: первичная проницаемость; характер насыщения паста пластовыми флюидами; объем внедрения и степень загрязнения буровой жидкостью. Цель: оценка влияния начальных фильтрационных характеристик призабойной зоны скважины на эффективность соляно-кислотной обработки. Методы. Были проведены опыты моделирующие соляно-кислотную обработку. Были использованы образцы с различными коллекторскими свойствами. В ряде экспериментов моделировалось загрязнение образцов буровым раствором. Результаты. Эффективность кислотной обработки образцов низкопроницаемой породы выше, чем в опытах с высокопроницаемыми кернами. В низкопроницаемых образцах сквозные каналы образуются при прокачке большего количества поровых объёмов кислотного раствора, чем в высокопроницаемых. Это связанно с тем, что раствор преимущественно расходуется на формирование новых каналов. Низкопроницаемые образцы имеют большую эквивалентную площадь образовавшихся каналов, что подтверждает большую эффективность кислотной обработки низкопроницаемых кернов. При снижении проницаемости коллектора вследствие загрязнения буровой жидкостью воздействие кислотного раствора происходит аналогично воздействию на незагрязнённый низкопроницаемый коллектор. Полученные результаты могут быть использованы при соляно-кислотной обработке на промысле с высокой вероятностью положительного эффекта. В дальнейшем необходимо дать экономическую оценку с учётом времени прорыва кислоты и необходимого количества соляной кислоты.

Injectivity of Multiple Slugs in Surfactant Alternating Gas Foam EOR: A CT Scan Study

SummaryA surfactant alternating gas (SAG) process is often the injection method for foam, on the basis of its improved injectivity over direct foam injection. In a previous study, we reported coreflood experiments on liquid injectivity after foam flooding and liquid injectivity after injection of a gas slug following steady-state foam. Results showed that a period of gas injection is important for the subsequent liquid injectivity. However, the effects of multiple gas and liquid slugs were not explored.In this paper, we present a coreflood study of injectivities of multiple gas and liquid slugs in an SAG process in a field core. Nitrogen and surfactant solution are either coinjected or injected separately into the sandstone core sample. The experiments are conducted at an elevated temperature of 90°C with a backpressure of 40 bar. Differential pressures are measured to quantify gas and liquid injectivities. Computed tomography (CT) scanning is applied to relate water saturation to mobility.During the injection of a large gas slug following foam, a bank in which foam completely collapses or greatly weakens forms near the inlet and propagates slowly downstream. During the subsequent period of liquid injection, liquid flows through the collapsed-foam bank much more easily than further downstream. Beyond the collapsed-foam region, liquid first imbibes into the whole cross section. In this region, liquid flows mainly through a finger of high liquid saturation. Our CT results suggest a revision of our earlier interpretation; the process of gas dissolution does not merely follow fingering but is evidently directly involved in the fingering process.Our results suggest that, in radial flow, the small region of foam collapse very near the well greatly improves injectivity. The subsequent gas and liquid slugs behave near the wellbore, affecting injectivity, in a way similar to the first slugs. Thus, the behavior and modeling of the first gas slug and first subsequent liquid slug is representative of near-well behavior in an SAG process. The trends observed in our previous work are reproduced in a low-permeability field core.

Determination of the Diffusion Coefficient of Supercritical CO2 in Low-Permeability Formation Cores

CO₂ diffusion in the oil phase in the presence of porous media is of great importance to forecast the performance of enhanced oil recovery and carbon dioxide capture and storage. When CO₂ is brought into contact with an oil phase, diffusion occurs. The indirect pressure-decay methodology has been applied successfully to determine the mutual diffusion coefficients of supercritical CO₂ and crude oil at temperature of 65 °C. Theoretically, a one-dimensional double-way mass transfer model incorporating the capillary and adsorption effects of porous media has been constructed to quantify the mutual dynamic diffusion coefficients. The crude oil has been characterized into five pseudo-components for the accurate description of the phase behavior of CO₂ gas and oil phases. An optimization method along with the PR equation of state is employed to determine each component’s diffusion coefficients in the gas and oil phases for the purpose of minimization of the difference between the experimental data and calculated results. Satisfactory agreements are obtained with a merely 0.97% pressure difference when a variable diffusion coefficient is implemented. The short-time experimental test and a long-time-duration calculation are recommended for further diffusion investigation. The capillary analysis gave a regressed fractal dimension of 2.7049 with the average absolute deviation of 0.602%. The adsorption phenomenon can be greatly influenced by the existence of heavy components. The heavier the components, the greater their impact on adsorption. Furthermore, a faster and enhanced diffusion process is observed at high pressure and temperature. The combination of several complex mechanisms leads to the initial gradual increase of the diffusion coefficient with time, and then, it arrives at a plateau, which is slightly different from the previous diffusion coefficient changing tendency mentioned in the literature. In the presence of a low-permeability formation core, the determined diffusion coefficients of CO₂ in the gas and liquid phases are increased from 4.38 × 10–⁹ to 6.21 × 10–⁹ and 6.16 × 10–¹⁰ to 9.21 × 10–¹⁰ m²/s when the system pressure is decreased from 18.2 to 12.11 MPa, respectively. In addition, the capillary effect can lead to a reduction of the diffusion coefficient in the oil phase but has little effect on the diffusion coefficient in the gas phase.

Applications of in situ polymerization microsphere with surfactant EOR in low-permeability and heterogeneous reservoirs

In order to enhance the low recovery efficiency in low-permeability and heterogeneous reservoirs resulted by water channeling during water flooding process, a series of flooding experiments using in situ polymerization microsphere (ISPM) with surfactant were conducted to achieve deep profile control in high conductivity water channels. Dynamic pressure measurement showed that ISPM demonstrated good injectability and profile control effect in low-permeability core of 20.22 mD, as the plugging rate was as high as 78.99%. At the same time, the electron microscopy results showed that the ISPM could migrate deeper into the core to form microsphere clusters to block the high conductivity channels. The core flooding experiments showed that the profile control effect of the composite slug consisted of surfactant and ISPM was much better than that of just ISPM alone. The front part of the slug consisting of BA with strong emulsifying capability and ultra-low interfacial tension can better exert the profile control effect of the ISPM and expand the sweep volume of the subsequent displacing agent better than surfactant TS with ultra-low interfacial tension. As a subsequent oil displacing agent after ISPM + BA profile control, surfactant BA with strong emulsifying capability and ultra-low interfacial tension, compared with AES and TS, achieved higher recovery efficiency. In low-permeability and heterogeneous reservoirs, ultra-low interfacial tension is screening crucial characteristic of surfactant, but emulsification capacity also plays a very important role. Combination of surfactant BA and ISPM could fully utilize the profile control effect of ISPM and the oil stripping effect of surfactant; the stage recovery efficiency was as high as 22.52%.

Novel in-depth profile control agent based on in-situ polymeric microspheres in low permeability reservoir

To solve the contradiction between the injectability of the profile control agent and its profile control ability in low-permeability reservoirs, a novel in-situ polymeric microsphere profile control agent is proposed. In-situ-polymeric microsphere (ISPM) emulsion was injected into the formation by polymerization to form microspheres for profile control. The emulsion was composed of divinylbenzene, acrylamide monomer, surfactant fatty acid polyoxyethylene ether sulfate, sorbitan oleate and p-hydroxyanisole. An ISPM particle diameter of 1.88 to 30.60 μm was achieved by adjusting the amount of Span80. The ISPM emulsion polymerization time was set to a maximum of 8.4 hours to ensures that the microsphere emulsion could be successfully injected into the formation. Polymerization reaction time increased with the increase of salinity. pH has no significant effect on the reaction time in the range of 5 to 8. Fourier transform infrared spectroscopy (FT-IR) experiments showed that the ISPM emulsion could be polymerized in tiny pores to form microspheres. Furthermore, multipoint pressure measurement experiment and electron microscopy results showed that the ISPM emulsion presented good injectability in low-permeability cores, and the microspheres formed after emulsion polymerization achieved deep plugging in cores. The injectability and blocking effect of the core with ISPM was found to be better than with microspheres (61.7%) for the blocking rate of the core at 10–15 cm deep reached 81.55%. The double-layer heterogeneous core flooding experiments showed that ISPM could expand the sweep volume of subsequent injection fluids and achieve improved oil production and water control. The composite slug composed of surfactant BA and ISPM demonstrated better profile control effect than the ISPM slug alone, and the enhanced oil recovery factor reached 15.65%.

Experimental Investigation of Hydrophobically Modified α-ZrP Nanosheets for Enhancing Oil Recovery in Low-Permeability Sandstone Cores.

Highly crystalline α-zirconium phosphate (α-ZrP) nanoparticles were synthesized and exfoliated into nanosheets, and then the hydrophilic nanosheets were modified into hydrophobic nanosheets with octadecyltrichlorosilane (OTS). Scanning electron microscopy, Fourier transform infrared spectroscopy, X-ray diffraction, and thermogravimetric analysis were applied to confirm the morphology and chemical structure of the nanosheets. Contact angle measurement was conducted to explore the wettability alteration of the hydrophobically modified α-ZrP nanosheets, and the result showed that the wettability of the core was changed into hydrophobicity. When ZrP–OTS nanosheets were injected during water-flooding, a Pickering emulsion will be formed. The droplet diameters and viscosities of the Pickering emulsions were measured. The hydrophobically modified α-ZrP nanosheets were applied in low-permeability sandstone cores and various concentrations were tested. The injectivity of the hydrophobically modified α-ZrP nanosheets was also studied and the result indicated that the nanosheets exhibit good injectivity. The mechanisms for enhancing oil recovery by utilizing hydrophobic α-ZrP nanosheets were analyzed: forming Pickering emulsions and increasing the viscosity of the displacing phase. Forming emulsions and increasing the viscosity of the flooding phase can enhance the microdisplacement efficiency, while good injectivity can also enhance the macrodisplacement efficiency. The result indicated the possibility of using hydrophobically modified α-ZrP nanosheets for enhancing oil recovery in a low-permeability reservoir.