Institute of Porous Flow and Fluid Mechanics

The most abundant natural biopolymer on earth, cellulose fiber, may offer a highly efficient, low-cost, and chemical-free option for wastewater treatment. Cellulose is widely distributed in plants and several marine animals. It is a carbohydrate polymer consisting of β-1,4-linked anhydro-D-glucose units with three hydroxyl groups per anhydroglucose unit (AGU). Cellulose-based materials have been used in food, industrial, pharmaceutical, paper, textile production, and in wastewater treatment applications due to their low cost, renewability, biodegradability, and non-toxicity. For water treatment in the oil and gas industry, cellulose-based materials can be used as adsorbents, flocculants, and oil/water separation membranes. In this review, the uses of cellulose-based materials for wastewater treatment in the oil & gas industry are summarized, and recent research progress in the following aspects are highlighted: crude oil spill cleaning, flocculation of solid suspended matter in drilling or oil recovery in the upstream oil industry, adsorption of heavy metal or chemicals, and separation of oil/water by cellulosic membrane in the downstream water treatment. Keywords: Cellulose, Wastewater treatment, Petroleum industry

The NMR relaxometry measurements have been designed and applied to quantitatively determine residual oil distribution during waterflooding in tight oil formations. A tight core sample is first saturated with water to measure its NMR transverse relaxation time ( T 2 ) spectrum. NMR T 2 spectrum is then measured for the core sample after it has been displaced with the fluorinated oil. Subsequently, the core sample is displaced with water until residual oil saturation is achieved, and the NMR T 2 spectrum is measured again at the end of the displacement. Subsequently, the constant-rate mercury injection method is used to experimentally measure the size of the pore and throat in the core sample. The residual oil saturation is determined as a function of pore size by comparing the difference between the first and last NMR T 2 spectrum. It is found from four core samples with permeability of 0.04–1.70 mD that the average pore size is in a range of 129–145 μm, and the pore throat has a radius of 0.17–0.89 μm. The original oil saturation is found to be 76–83%, whereas the oil recovery factor is 36–62%; 4–27% of the original oil is distributed in pores larger than 100 μm, 50–54% in pores from 10 to 100 μm, and 21–46% in pores and throats smaller than 10 μm. Residual oil saturation is 1–2% in pores larger than 100 μm, 29–64% in pores from 10 to 100 μm, and 34–69% in pores and throats smaller than 10 μm.

Rate-controlled Hg injection experiments, NMR core tests and core flooding experiments are carried out to study the low permeability cores from the Daqing and Changqing oilfields. The forming and affecting factors are studied to demonstrate why the pseudo threshold pressure gradient to flow should be overcome. Because of the boundary layer caused by interaction between solid and fluid and the micro throats of low permeability reservoirs, the pseudo threshold pressure should be overcome for fluid to flow in low permeability reservoirs. Few throats are involved in the flow and the seepage cross section area is also less at lower pressures. The throats number and the seepage cross section area increase with the increasing of flooding pressure. The pore structure and movable fluid saturation of low permeability reservoirs have remarkable influence on the pseudo threshold pressure to flow, the bigger the mainstream throats and the movable fluid saturation, the less the pseudo threshold pressure to flow. The pseudo threshold pressure gradient to flow is a characteristic parameter of nonlinear flow degree and seepage ability and it is a synthetic symbol of pore structure and movable fluid saturation.

The application and characteristics of CO2 flooding in the USA were analyzed and summarized. Supporting techniques of CO2 flooding were generalized, and then the enlightenment was expounded for CO2 flooding in China. The development process and forming reasons of CO2 flooding technology were analyzed and summarized based on systematic tracking of EOR survey data all over the world and sufficient investigation of CO2-EOR technology application. With the number of CO2 flooding projects, scale and annual production as indicators, the current situation of American CO2-EOR technology was evaluated. The characteristics of the projects and development-driving force of CO2 flooding in America were also summed up. The characteristics of formation properties, crude oil properties and project timings of American CO2 miscible flooding projects were outlined emphatically. Meanwhile, the application scale and reservoir adaptability differences between American CO2 miscible and immiscible flooding were comparatively analyzed. A series of supporting techniques were illuminated with the SACROC CO2 flooding project as an example. The challenges, technical bottlenecks and suggestions were analyzed and proposed for the promotion of CO2 miscible flooding technology in China.

Spontaneous imbibition is significantly influenced by rock wettability, and it has been extensively studied in core-based experiments and numerical simulations owing to its important role in the development of oil/gas reservoir. Due to the fine pore structure and complex wettability of tight sandstone, an in-depth exploration of the effects of wettability on the pore-scale flow physics during spontaneous imbibition is of great value to complement traditional experimental studies and enhance the understanding of microscopic flow mechanisms during the development of tight oil reservoirs. Based on a X-ray computed tomography scanning experiment and a lattice Boltzmann multiphase model, in this work, we systematically investigate the effects of different hydrophilic strengths on the evolution of the imbibition fronts within the micropores and the degree of nonwetting fluid recovery during spontaneous imbibition of tight sandstone. The results show that the wettability significantly affects the morphological characteristics of the imbibition fronts. Under strong hydrophilic conditions, the wetting fluid preferentially invades the pore corner in the form of angular flow. As the contact angle increases, the hysteresis effect at the main terminal interface decreases, and the two-phase interface becomes regular and compact. Wettability also significantly affects the imbibition rate and the nonwetting fluid recovery degree. The smaller the contact angle, the faster the imbibition rate and the higher the recovery degree of nonwetting fluids during the cocurrent spontaneous imbibition.

To exert the imbibition between cracks and matrix effectively and enhance the development effect of tight oil reservoirs, a physical simulation method for imbibition in different scales of cores is developed by combining a high-pressure large-model physical simulation system and nuclear magnetic resonance technology (NMR) to investigate the influencing factors of imbibition process in tight reservoirs, and construct a quantitative evaluation method for the imbibition in water flooding. The results show that in the process of counter-current imbibition, the lower the permeability, the later the oil droplet precipitation, the longer the imbibition equilibrium time, and the lower the recovery degree. Fractures can effectively expand the area of imbibition and the front edge of imbibition in the contact between the dense matrix and water, reduce the resistance of oil discharge, and improve the imbibition speed and the degree of recovery. The more hydrophilic the rock, the higher the imbibition rate and imbibition recovery of tight rocks. In the process of co-current imbibition, the lower the permeability, the more obvious the imbibition, and the displacement recovery is positively correlated with permeability, while the imbibition recovery is negatively correlated with the permeability. It also shows that the imbibition distance of the cyclic water injection is greater than that of the counter-current imbibition, and the higher the permeability and the injection multiple, the longer the imbibition distance. The combination of large-scale volume fracturing with changing reservoir wettability and cyclic water injection is conducive to improving the imbibition ability of tight reservoirs.

Isothermal adsorption and desorption experiments under different temperatures were carried out with the Longmaxi Formation shale samples collected from southern Sichuan. The experimental results show that temperature affects the adsorption and desorption capacity of shale, the adsorption capacity of shale decreases with temperature increase. The adsorption curve and desorption curve of shale are not coincident and the thermodynamic reason for the hysteresis of the desorption curve is that the isosteric heat of the shale adsorption process is greater than that of the desorption process. The Langmuir model and desorption model can describe the isothermal adsorption and desorption processes very well, respectively. Isothermal adsorption and desorption curves under different temperatures can be predicted by isosteric heat curves which match the experimental results. Shale gas production is a process of gas desorption and the desorption characteristics directly impact the production of shale gas, so the desorption model should be taken into consideration in the shale gas production forecast and numerical simulation.

Microbial enhanced oil recovery (MEOR) technology is an environmental-friendly EOR method that utilizes the microorganisms and their metabolites to recover the crude oil from reservoirs. This study aims to research the potential application of strain SL in low permeability reservoirs. Strain SL is identified as Bacillus subtilis by molecular methods. Based on the mass spectrometry, the biosurfactant produced by strain SL is characterized as lipopeptide, and the molecular weight of surfactin is 1044, 1058, 1072, 1084 Da. Strain SL produces 1320 mg/L of biosurfactant with sucrose as the sole carbon source after 72 h. With the production of biosurfactant, the surface tension of cell-free broth considerably decreases to 25.65 ± 0.64 mN/m and the interfacial tension against crude oil reaches 0.95 ± 0.22 mN/m. The biosurfactant exhibits excellent emulsification with crude oil, kerosene, octane and hexadecane. In addition, the biosurfactant possesses splendid surface activity at pH 5.0-12.0 and NaCl concentration of 10.0% (w/v), even at high temperature of 120 °C. The fermentation solution of strain SL is applied in core flooding experiments under reservoir conditions and obtains additional 5.66% of crude oil. Hence, the presented strain has tremendous potential for enhancing the oil recovery from low-permeability reservoirs.

Combined with NMR, core experiment, slim-tube tests, nano-CT and oil composition analysis, the mechanism of CO2 enhanced oil recovery had been studied. CO2 flooding under supercritical state could achieve higher oil recovery. In the process of crude oil displaced by supercritical CO2, the average oil recovery was 46.98% at low displacement pressures and 73.35% at high displacement pressures. The permeability of cores after CO2 flooding was only 28%–64% of those before flooding. As to the expelled oil, the contents of asphaltenes and non-hydrocarbons decreased, and saturated hydrocarbons of above C25 were absent in some samples, indicating that they had been retained in cores as demonstrated by CT and NMR experiments. In slim-tube tests, the heavy components of oil were expelled when the pressure increased to 30 MPa. There was a reasonable bottom hole pressure (BHP) below which the heavy components driven out from the far-well zone would deposit in the near-well zone, and when the pressure was too high, the nonhydrocarbon detention may cause block. The smaller throat and worse physical properties the porous media had, the higher displacement pressure would be required to achieve a good oil displacement efficiency. The increase in displacement pressure or time of interaction between oil and CO2 could effectively enhance oil recovery.

The estimate ultimate recovery (EUR) of shale gas in individual well is affected by many factors so that it is difficult to predict accurately. Data-driven methods based on geological and engineering parameters are currently one of the mainstream methods for predicting EUR. However, the importance of early data from gas wells is often overlooked. Therefore, this research set out to use early data, including production and flowback rate data, to develop machine learning models. With the ability to analyze the data by machine learning, the controlling factors on EUR have been analyzed quantitatively. Four schemes have been designed to develop the model, and various machine learning techniques (K-Nearest Neighbor (KNN), Support Vector Machine (SVM), Random Forest (RF), Gradient Boosting Decision Tree (GBDT)) were applied to process the complex patterns in the data. The results show that, except 30-day flowback rate, the most important factor for EUR is the early production data. The relationship between the early flowback rate and EUR is poor. It is not enough to predict EUR accurately provided that only using the flowback rate data. Good prediction results have been obtained by choosing the most important factors. Among the four algorithms, SVM is considered to be the most reliable model because it is suitable for small data sets and performs well in dealing with nonlinear relationships between variables. The mean absolute percentage error is 13.41% in the test set 49 wells, which can be used as the optimal algorithm for EUR prediction only based on early data.

Aiming at the development situation of the Xinjiang oil field, the mechanism of enhancing oil recovery by the Polymer-Surfactant Binary Flooding (SP Flooding) was studied through SP Flooding sand pack, natural core and micro model experiments, and Optimum SP Flooding formula is provided. The results show that the enhanced oil recovery by the SP Flooding increases with the increase of the viscosity ratio between water and oil or the decrease of the interfacial tension. Capillary displacement ratio can reflect the synergetic effect of viscosity and interfacial tension and help screen out the optimum formula of the SP Flooding. For Qizhong block in Xinjiang Oilfield, where the critical viscosity ratio of SP flooding solution is 2.5, the order of magnitude of the critical interfacial tension is 1×10−2 mN/m, and the order of magnitude of the critical capillary displacement ratio is 1×10−3, the optimum formula of the SP Flooding composed of 0.3% KPS-1+1 115 mg/L HPAM can enhance the oil recovery by 23.96%. The polymer in the SP Flooding system increases the viscosity of the displacement fluid, accordingly the fluidity of the aqueous phase reduces and that of the oil phase increases, and the resulting decrease of the mobility ratio can control waterflood fingering, make water absorption thickness increase, enhance sweep efficiency and thus activate the residual oil trapped in dead ends. The surfactant decreases interfacial tension, and the resulting decrease of adhesion work makes residual oil emulsified, stripped, wiredrawn and easy to move. In addition, the emulsion liquid further increases the viscosity of the aqueous phase, and with interaction of lower interfacial tension and high viscosity of the emulsion liquid, the capillary displacement ratio is greatly enhanced, which in turn improves the oil displacement efficiency by displacing isolated-island, columnar and membranous residual oil, and consequently a higher oil recovery.

Pore–throat size is a key parameter for the assessment of reservoirs. Tight sandstone has the strong heterogeneity in the distribution of pores and throats; consequently, it is very difficult to characterize their distributions. In this study, the existing pore–throat characterization techniques were used jointly with scanning electron microscopy (SEM), low-temperature nitrogen adsorption (LTNA), high-pressure mercury intrusion (HPMI), and rate-controlled mercury intrusion (RCMI) technologies to highlight features of throat sizes and distribution of pores in tight sandstone reservoirs of the Y Basin in China. In addition, full-scale maps (FSMs) were generated. The study results show that key pore types in reservoirs of the Y Basin include residual intergranular pores, dissolved pores, clay mineral pores, and microfractures. LTNA can effectively characterize the distribution of pore–throats with a radius of 2–25 nm. HPMI test results show that tight sandstones contain throats with a radius less than 1000 nm, which are mainly distributed in 25–400 nm and have a unimodal distribution. RCMI tests show that there is no significant difference in pore radius distribution of the tight sandstones, peaking at approximately 100,000–200,000 nm; the throat radius of tight sandstones varies greatly and is less than 1000 nm, in agreement with that of HPMI. Generally, the pore–throat radius distribution of tight sandstones is relatively concentrated. By using the aforementioned techniques, FSM distribution features of pore–throat radius in tight sandstone can be characterized effectively. G6 tight sandstone samples develop pores and throats with a radius of 2–350,000 nm, and the pore–throat types of tight sandstone reservoirs in Y basin are mainly mesopores and macropores.

Based on the basic principle of the porosity method in image segmentation, considering the relationship between the porosity of the rocks and the fractal characteristics of the pore structures, a new improved image segmentation method was proposed, which uses the calculated porosity of the core images as a constraint to obtain the best threshold. The results of comparative analysis show that the porosity method can best segment images theoretically, but the actual segmentation effect is deviated from the real situation. Due to the existence of heterogeneity and isolated pores of cores, the porosity method that takes the experimental porosity of the whole core as the criterion cannot achieve the desired segmentation effect. On the contrary, the new improved method overcomes the shortcomings of the porosity method, and makes a more reasonable binary segmentation for the core grayscale images, which segments images based on the actual porosity of each image by calculated. Moreover, the image segmentation method based on the calculated porosity rather than the measured porosity also greatly saves manpower and material resources, especially for tight rocks.

A unique and cost effective chemical route has been carried out for the synthesis of a polyaniline–titanium oxide (PANI–TiO₂) composite thin film at room temperature.

Abstract Rocks are heterogeneous multiscale porous media: two rock samples with identical bulk properties can vary widely in microstructure. The advent of digital rock technology and modern 3‐D printing provides new opportunities to replicate rocks. However, the inherent trade‐off between imaging resolution and sample size limits the scales over which microstructure and macrostructure can be identified and related to each other. Here, we develop a multiscale digital rock construction strategy by combining X‐ray computed microtomography and focused‐ion beam (FIB)‐scanning electron microscope (SEM) images, and we apply the technique to a tight sandstone. The computed tomography (CT) scanning images characterize macroscale pore structures, while the FIB‐SEM images capture microscale pore textures. The FIB‐SEM images are then coupled to CT images via a template‐matching algorithm and superposition. Bulk properties, including porosity and pore and throat size distribution, can be recovered with this approach. Permeability prediction with a pore network model for the largest connected pore network are 3 orders and 1 order of magnitude greater than the bulk rock measured value using the CT‐only and the SEM‐CT coupled images, respectively.

The high pressure static adsorption curves of shale samples from Silurian Changning-Weiyuan Longmaxi Formation were tested by using high pressure isothermal adsorption equipment. The physical modeling of depletion production was tested on single cores and multi-core series by using self-developed shale gas fluid-solid coupling experiment system. The adsorption and desorption laws were summarized and a high pressure isothermal adsorption model was established. The calculation formula of gas content was corrected, and the producing law of adsorption gas was determined. The study results show that the isothermal adsorption law of the shale reservoir under high pressure was different from the conventional low pressure. The high pressure isothermal adsorption curve had the maximum value in excess adsorption with pressure change, and the corresponding pressure was the critical desorption pressure. The high pressure isothermal curve can be used to evaluate the amount of adsorbed gas and the producing degree of adsorption gas. The high pressure isothermal adsorption model can fit and characterize the high pressure isothermal adsorption law of shale. The modified gas content calculation method can evaluate the gas content and the proportion of adsorbed gas more objectively, and is the theoretical basis of reserve assessment and production decline analysis. The producing degree of adsorption gas is closely related to the pressure, only when the reservoir pressure is lower than the critical desorption pressure, the adsorption gas can be produced effectively. In the process of gas well production, the pressure drop in the near-well area is large, the production of adsorption gas is high; away from the wellbore, the adsorption gas is low in production, or no production.

In the exploitation of tight oil and gas reservoirs, multi-stage hydraulic fracturing technology is mainly used and a complex system of fractures and matrix is formed after fracturing. In the process of field production, it is reported that longer shut-in time results in good oil and gas production rate. The reason of this phenomenon is considered as the spontaneous imbibition of oil and gas driven by capillary force in reservoirs. Spontaneous imbibition is an important recovery mechanism in low permeability and tight reservoirs. The pore structure of tight rocks is very complex and the pore connectivity is poor. It is of great significance to study the imbibition mechanism of tight porous rocks. Through the combination of spontaneous imbibition experiments, this work studies the influencing factors and reveals the mechanism of the gas/oil recovery from tight reservoirs. The spontaneous imbibition experiments were carried on the gas/water system and the oil/water system. The swelling clay minerals in shales will enhance the imbibition. Cores with high permeability have small recovery, which may be due to the low capillary force in tight cores. Fractures can promote the imbibition volume of tight cores. Cited as : Gao, L., Yang, Z., Shi, Y. Experimental study on spontaneous imbibition characteristics of tight rocks. Advances in Geo-Energy Research, 2018, 2(3): 292-304, doi: 10.26804/ager.2018.03.07

Abstract With continued increasing construction of both electrified facilities and buried high‐strength pipelines in China, stray current corrosion defects have become an nonignorable threat for these pipelines. A comprehensive investigation on a new failure pressure prediction model for high‐strength pipes with stray current corrosion defects was conducted in this study. The mechanism of stray current corrosion in steel pipes was firstly elaborated in brief. After that, a parameterized finite element model for stress analysis of pipes with external corrosion defects was programmed by APDL code developed by general software ANSYS. By comparing numerical results with full‐scale experimental results, both the numerical model and the failure criteria for pipe burst were proven to be reasonable. Based on the finite element model, parametric analysis was performed using a calculation matrix set by orthogonal testing method to investigate the effects of three main dimensionless factors, that is, ratio of pipe diameter to wall thickness, nondimensional corrosion defect length, and nondimensional corrosion defect depth on pipe's failure pressure. Utilizing the parametric analysis results as database, a multilayer feed‐forward artificial neural network (ANN) was developed for failure pressure prediction. By comparison with experimental burst test results and results of previous failure pressure estimation model, the ANN model results were proven to have both high accuracy and efficiency, which could be referenced in residual strength or safety assessment of high‐strength pipes with corrosion defects.

A systematic study had been carried out to get insight into the micellar behavior of anionic lipopeptide (LT) and nonionic sophorolipid (SL) in their different mass ratio mixed state using the technique of tensiometry. The models proposed by Clint, Rubingh and Gibbs et al. had been employed to interpret the formation of mixed micelles and found out synergism. The obtained experimental critical micelle concentrations (CMC) were lower than the ideal CMCs, indicating negative deviation from ideal behavior for all multi-component mixed micelles formation. A suited binary bio-surfactant mixing system was selected as the washing agents to treat the oily sludge produced from Huabei oilfield by the thermal bio-surfactant washing method. The results showed that in case of the mass ratios of 8:2 the CMC was dramatically decreased and synergism was the strongest in LT and SL bi mixed surfactant systems. The studied binary mixed bio-surfactant system showed higher washing efficiency for oily sludge than single surfactant system. In addition, the washing power of binary mixed bio-surfactants towards oily sludge was the best at below washing conditions: (a) the concentration of the mixed system (100 mg/L), (b) temperature (55 ℃), (c) ratio of sludge/liquid (1:3), (d) washing time (3 h), and (e) stirring speed (300 rpm). Certainly, the washing abilities of the selected surfactants not only depend on their mixing ratio and washing conditions but also associate with microstructure and mineral components of oily sludge.

A key constraint in the application of microfluidic technology to subsurface flow and transport processes is the surface discrepancy between microchips and the actual rocks/soils. This research employs a novel layer-by-layer (LbL) assembly technology to produce rock-forming mineral coatings on microchip surfaces. The outcome of the work is a series of 'surface-mimetic micro-reservoirs (SMMR)' that represent multi-scales and multi-types of natural rocks/soils. For demonstration, the clay pores of sandstones and mudrocks are reconstructed by representatively coating montmorillonite and kaolinite in polydimethylsiloxane (PDMS) microchips in a wide range of channel sizes (width of 10-250 μm, depth of 40-100 μm) and on glass substrates. The morphological and structural properties of mineral coatings are characterized using a scanning electron microscope (SEM), optical microscope and profilometer. The coating stability is tested by dynamic flooding experiments. The surface wettability is characterized by measuring mineral oil-water contact angles. The results demonstrate the formation of nano- to micro-scale, fully-covered and stable mineral surfaces with varying wetting properties. There is an opportunity to use this work in the development of microfluidic technology-based applications for subsurface energy and environmental research.