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Journal of Petroleum Science & Engineering
Elsevier Science B.V.
Journal of Petroleum Science & Engineering

Elsevier Science B.V.

0920-4105

Journal of Petroleum Science & Engineering/Journal Journal of Petroleum Science & Engineering
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    The pore-scale mechanisms of surfactant-assisted spontaneous and forced imbibition in water-wet tight oil reservoirs

    Bao CaoXiangguo LuKun Xie
    11页
    查看更多>>摘要：The imbibition of water with surfactants, including spontaneous imbibition and forced imbibition, is of great significance for enhanced oil recovery (EOR) in tight sandstone reservoirs. Up to now, the migration behaviors of the water and the oil in pores of different sizes, as well as the mechanisms of both spontaneous imbibition and forced imbibition with different surfactants, have not been comprehensively addressed yet. This work first measured the oil-water interfacial tensions (IFTs) and the contact angles in oil-water-rock system with two types of surfactants, namely medium-IFT (0.1-10 mN/m) and low-IFT (0.001-0.1 mN/m) surfactants, at different concentrations to comprehend the functionalities of surfactants on oil recovery. Secondly, the pore size distributions of tight sandstones were determined by the high-pressure mercury intrusion (HPMI) and the nuclear magnetic resonance (NMR) technology to characterized the pores into three types (micropores, mesopores, and macropores) according to the pore sizes. Eventually, this work presented the oil recovery results in these three types of pores for spontaneous and forced imbibition using the two types of surfactants in water-wet tight core samples. Both spontaneous and forced imbibition results showed that the oil recoveries with surfactants were higher than those with brine, which was primarily attributed to the increased oil in the mesopores and the macropores. However, the addition of low-IFT surfactants apparently reduced the oil recovery in micropores, hence resulted in a lower oil recovery in comparison with the medium-IFT surfactants. It was also found that the oil in micropores contributed more than 50% of the oil recovery in the imbibition, except for the imbibition with low IFT, due to the high initial oil volume ratios in micropores; there could be a moderate IFT value (e.g., 0.1-1 mN/m) with the use of surfactants to obtain the highest oil recovery. Moreover, in comparison with the spontaneous imbibition, the forced imbibition could enhance the imbibition of water into the micropores but prevent the oil from being extracted from the mesopores and the macropores, which consequently led to a higher contribution of the micropores on oil recovery than that of the larger pores, especially the mesopores.
      原文链接:
    • NSTL

    Effects of surfactants on dispersibility of graphene oxide dispersion and their potential application for enhanced oil recovery

    Kaili LiaoZhangkun RenLipei Fu
    11页
    查看更多>>摘要：As a new type of oil displacement agent, nanofluid has shown great application potential in the field of enhanced oil recovery. Good dispersion and high stability of nanofluids are the prerequisites for engineering application. In this paper, the water-based graphene oxide (GO) nanofluid was taken as the research object, and the influencing factors of dispersion stability were systematically studied. The water-based nanofluid based on GO was formulated, and its oil displacement potential was studied. The effects of ultrasonic dispersion time, GO dosage and surfactant on the dispersion stability of GO in aqueous solution were investigated by turbidity experiment and conductivity experiment. The results showed that amphoteric surfactant disodium cocoamphodiacetate (CAD) had good dispersion stability for GO. CAD/GO dispersion not only decreased the oil/water interfacial tension to 10~(-2) mN/m, but also had good emulsifying effect and kept the emulsion stable. In the micromodel flooding test and core flooding test, CAD/GO dispersion effectively displace the residual oil in porous media and improve crude oil recovery. In the core flooding test, the oil recovery of CAD/GO dispersion (11.8%) was higher than CAD aqueous solution (6.7%), which was attributed to its better interfacial property and emulsifying property. These results indicated that the CAD/GO dispersion was promising for application in enhanced oil recovery (EOR).
      原文链接:
    • NSTL

    Evaluation of the effects of homogenizing matrix block sizes on the simulation of naturally fractured reservoirs

    Amirhossein AghabarariMojtaba Ghaedi
    12页
    查看更多>>摘要：A vast amount of recoverable oil is buried in naturally fractured reservoirs. Due to the heterogeneous nature of matrix and fracture systems, there are many complexities in the simulation and production of these kinds of reservoirs. Fractures in naturally fractured reservoirs may be caused by various natural factors such as tectonic forces. Fracture distribution does not have a systematic pattern in naturally fractured reservoirs, and fractures are scattered across the formation. For the sake of simplicity, uneven distribution of fractures is not completely considered within practical reservoir simulation methodologies such as the commonly used dual-porosity approach. Using the dual-porosity methods, naturally fractured reservoirs are divided into simulation cells consisting of several matrix blocks. Against the nature of naturally fractured reservoirs, in the dual-porosity method, the fractures are often uniformly spread throughout the entire reservoir, and the sizes of matrix blocks inside the simulation cells are considered equal. For many years the assumption of homogenized matrix blocks in simulation cells has been used in the industry without proper evaluation of its effect on simulation results. This work examines the assumption of uniform matrix block size on the simulation results of naturally fractured reservoirs. An approach was proposed to create a simulation cell with randomly distributed matrix blocks to mimic the actual condition of naturally fractured reservoirs. Furthermore, realistic simulation approaches were utilized to investigate the oil recovery factor of different non-homogenized simulation cells during gravity drainage and imbibition processes. Also, the recovery factor performances of non-homogenized simulation cells were compared with simulation cells with uniform matrix block sizes created with different homogenization methods. An examination of the results revealed that a significant amount of inaccuracy in the simulation results could be caused by homogenization. Moreover, two types of homogenization approaches were used. In the first approach, a simulation cell with homogenized matrix block sizes based on the arithmetic mean of variable size matrix blocks was built. Homogenized matrix blocks in the second approach were built according to the arithmetic mean size of matrix blocks in different x, y, z directions. The first homogenization method resulted in less error compared to the second one. As compared with the gas invaded zone, simulation results of the water invaded zone are more error-prone. The findings of this work can help for better understanding the homogenization effect and prove that disregarding the heterogeneity of matrix blocks may lead to severe errors in the simulation results of naturally fractured reservoirs. The outcome also highlights the need for a more precise modeling and simulation approach for naturally fractured reservoirs.
      原文链接:
    • NSTL

    Insights on the penetration and migration of chemically cross-linked systems in porous media

    Yan LiangCheng JinZenglin Wang
    13页
    查看更多>>摘要：Using the sand-packed tubes with different lengths (0.2-20 m) and different long flat-sand-inclusion visualization models, the penetration and migration laws, in-depth dynamic gelation and plugging characteristics, and the related mechanism of chemically cross-linked systems (HPAM/Cr~(3+)) in porous media are investigated. The results show that there is an optimal concentration ratio between the polymer and the crosslinking agent, and the system of 4000 mg/L HPAM and 3000 mg/L SD-307 can obtain the gel with maximum strength (grade G) and breakthrough pressure gradient (3.13 MPa/m). The relatively weak system of 1800 mg/L HPAM +1000 mg/L SD307 (grade C) can present a similar injection pressure with the strong system of 4000 mg/L HPAM + 3000 mg/L SD307. Moreover, the onset and equilibrium of cross-linking agent production respectively lags behind polymer by at least 1.38 PV and 20.5 PV, and the adsorption amount of the crosslinking agent is 5111 μg/g greater than that of the polymer. Compared strong system (grade G) with the weak one (grade C), the former only has slight difference with the latter in the production and equilibrium of polymer but has significant difference in cross-linking agent. The corresponding injected volumes of production and equilibrium of polymer present significantly increase before the length of 1 m. Furthermore, the effluent of strong cross-linked system in 8 m in front of 20 m-long sand-packed tube exhibits the effective gelation and can achieve efficient plugging. On the contrary, the gel strength is very low or even the gelation is difficult as the migration distance exceeds 8 m. Although a greater fractional flow more than 75% can be achieved at high permeability under heterogeneous condition, the sweep of subsequent water to the low permeability layer after injecting the system become worse and worse with increasing injected volume (0.1-0.9 PV) due to the damage to the low permeability layer.
      原文链接:
    • NSTL

    Physical and Mechanical characteristic relationships of Late-Cretaceous to Eocene reservoir rocks in the Maui, Maari and Manaia Fields, New Zealand

    Sophie HillMarlene C VilleneuveDavid McNamara
    16页
    查看更多>>摘要：Constraint on the rock strength parameters within the subsurface is a fundamental requirement for accurate geomechanical modelling of aspects of reservoir stability and regional scale basin interactions. Insufficient rock strength data for offshore lithologies within the Taranaki Basin leads to a dependence on uncalibrated, empirical relationships applied in conjunction with wireline measurements for rock strength predictions. Use of these uncalibrated empirical relationships can lead to unreliable strength estimates, which reduces the confidence in geomechanical modelling and the subsequent solutions for the region. We conducted uniaxial and triaxial experiments on cores from offshore Taranaki reservoir rocks from 2000 to 4000 m depth to develop the first, calibrated, empirical rock strength relationships for reservoir rocks of the Taranaki Basin, using both grain size and porosity as input parameters. We show that grain size and porosity can be used as predictive tools for determining Hoek-Brown and Mohr-Coulomb failure criterion parameters for petroleum geomechanics. As mean grain diameter and porosity are the dominant control on rock strength, we infer that rock strength parameters within the Taranaki Basin will follow a similar spatial distribution as the reservoir sandstone facies. which are dominantly defined by grain size. We also show that the empirical relationships we developed with this dataset can be locally calibrated for other parts of the Taranaki basin, and indeed for other sandstones, such as the Buntsandstein from the Rhine Graben. France. Finally, we provide an approach by which grain size (+/- porosity) can be used to approximate the input parameters for the Hoek-Brown failure criterion in the absence of laboratory experiments. We propose, therefore, that the empirical relationships presented herein can be used to link facies descriptions with first-order estimates of mechanical properties at the basin scale.
      原文链接:
    • NSTL

    Aqueous solution of 3-pentanone for enhanced oil production from tight porous media

    Francisco J. Arguelles-VivasGayan A. AbeykoonMingyuan Wang
    10页
    查看更多>>摘要：This paper presents an experimental study of improved oil recovery from fractured tight cores by huff-n-puff of the aqueous solutions of 3-pentanone. The huff-n-puff experiments with different 3-pentanone concentrations were compared. Naturally sulfate-rich brine of low salinity was used as the injection brine. Results show that the 3-pentanone solution recovered more oil from the matrix than the injection brine alone. The improved oil recovery by 3-pentanone increased to 28.6% of the original oil in place as the 3-pentanone concentration increased up to 2.85 wt% in the injection brine. However, the huff-n-puff experiment with the 1.07-wt% 3-pentanone solution showed the highest efficiency measured by the mass ratio of the produced oil to the injected 3-pentanone, 11.1. That is, an optimal concentration of 3-pentanone appeared to exist.
      原文链接:
    • NSTL

    A new experimental method for comparing solvents in steam-solvent coinjection for bitumen recovery under controlled thermodynamic conditions

    Kai ShengHassan AmerYoung Liu
    21页
    查看更多>>摘要：Solvent-aided steam-assisted gravity drainage (SA-SAGD) involves the interplay between phase behavior and fluid flow near the edge of a steam chamber, which affects the mixing of solvent with bitumen. The mixing of solvent with bitumen (i.e., dispersion) results in dilution of the bitumen and can improve the energy efficiency of SAGD. However, it is often difficult to analyze this complex interplay through large-scale steam injection experiments because of the transient chamber-edge thermodynamic conditions. This paper presents an experimental program that compares the bitumen gravity drainage with steam injection (SAGD) and solvent-steam co-injection (SA-SAGD) under controlled thermodynamic conditions. In addition to SAGD as the base case, two sets of SA-SAGD were performed with 20 mol% C4 and 10 mol% C8 in the coinjected vapor at 3500 kPa. The experiments used a sand-pack of 3-inch diameter and 15-inch length, which was placed in a 25-L cylindrical pressure vessel. The sand-pack was surrounded by one-inch annular space, into which the vapor phase was injected under controlled pressure, temperature, and composition. Oil production and temperature profiles inside and outside the sand-pack were recorded for all experiments. Excavated samples from the sand-pack were analyzed after the experiments. The total recovery factors for SAGD, C4-SAGD, and C8-SAGD were 78%, 84%, and 89%, respectively. The recovery factors at 1 h for SAGD, C4-SAGD, and Cg-SAGD were 71%, 80%, and 85%, respectively. The peak oil rate was 9.8 cm~3/min with SAGD, 14.6 cm~3/min with C4-SAGD, and 31.3 cm~3/min with C8-SAGD. The SA-SAGD cases resulted in markedly better results than the SAGD case, and Cg-SAGD yielded more rapid oil drainage than C4-SAGD. The SAGD experimental data were history-matched using a numerical simulation model. Based on the calibrated numerical model, the SA-SAGD experimental data were history-matched by adjusting the dispersion coefficient to model the mixing between the solvent and bitumen. The apparent dispersion coefficients for C4 and Cg in bitumen were determined to be 0.012 m~2/day and 0.093 m~2/day, respectively. The experimental program verified in this research offers a way to systematically compare different solvents for SA-SAGD with their quantifiable dispersion coefficients under given chamber conditions.
      原文链接:
    • NSTL

    LBM simulation of non-Newtonian fluid seepage based on fractional-derivative constitutive model

    HongGuang SunLijuan JiangYuan Xia
    9页
    查看更多>>摘要：This paper proposes a truncated fractional-derivative constitutive model to consider the non-locality of non-Newtonian fluids. The single relaxation time lattice Boltzmann method (SRT-LBM) is used to simulate seepage of non-Newtonian fluid. The results are verified by analytical solutions while the flow characteristics of non-Newtonian fluids are explored. In the case of laminar flow, the steady-state velocity aistribution of shear-thinning and shear-thickening fluids after 10~5 - time steps are compared with the analytical distribution, and the results show an agreement within 2%. For non-Newtonian index simulation, the thicker the fluid, the larger the velocity and the more volatility, implying the more complex flow characteristics for shear-thickening fluid. Additionally, small fractional indexes correspond to large computational errors in regions away from the boundary. Flow characteristics research shows that the seepage of power-law fluid in fractured media exhibits non-Darcy phenomenon. As the fractional index decreases (i.e., fluid becomes thicker), the obstruction of the medium increases, resulting in a reduction in the medium's permeability. The shear stress of non-Newtonian fluids can be memorized by the mean section velocity distribution, and the memory capacity of different fluids can be captured by the fractional index. Furthermore, the fractional-derivative critical Reynolds number is introduced to clarify the applicable conditions of non-Newtonian flow equations, which increase with diameter and initial kinematic viscosity. The fractional-derivative critical Reynolds number of dilatant fluids is larger than pseudoplastic fluids, due to the memory properties of the fluid as well as the physical characteristics.
      原文链接:
    • NSTL

    Water flooding of sandstone oil reservoirs: Underlying mechanisms in imbibition vs. drainage displacement

    Danial ArabSteven L. BryantOle Torsaeter
    16页
    查看更多>>摘要：In this work the effect of wettability in waterfloods of viscous oil is investigated in a combination of experiments in sandpacks and microfluidic chips. Thirty-nine sand-pack flooding experiments were conducted to investigate the effect of core wettability, oil viscosity, and injection velocity on oil recovery to water flooding. An in-line densitometer, installed downstream of the core, was used to record the instantaneous fluid production and help understanding the mechanism of oil displacement in porous media. Additional microfluidic experiments were conducted to understand the mechanism of viscous oil displacement in imbibition vs. drainage. The effect of injection velocity on oil recovery is a strong function of core wettability and oil viscosity. In water-wet systems, below a critical viscosity (～60 mPa s), increasing injection velocity enhances oil displacement. In more viscous oil systems, injection velocity reduction improves imbibition. This is confirmed through visualization in microfluidic tests. Post breakthrough bypassed oil is produced in the form of low viscosity oil in water emulsion. In oil-wet waterflooding, oil imbibition into the preformed water channels pinches off(snaps-off) some continuous fingers, diverting water to un-swept regions. This temporary channel closure can explain the cyclic pressure build-ups observed oil-wet core flooding experiments, casein oil-wet systems, oil is produced as a series of viscous oil slugs rather than an emulsion. A new dynamic dimensionless time is presented to quantify imbibition time to which imbibition data are well correlated. This number along with the previously presented "viscous drainage number" can quantify different mechanisms responsible for oil displacement in systems of different viscosity ratio, injection velocity, and core wettability. The proposed dimensionless numbers can be used to determine expected viscous oil recovery efficiency in different wettability systems.
      原文链接:
    • NSTL

    Permeability characteristics of CH4, CO2, and N2 during the whole process of adsorption in coal with accumulated pressure under triaxial stresses

    Li LiHang LongShu-gang Li
    9页
    查看更多>>摘要：This study aimed to explore the seepage characteristics of N2, CH4, and CO2 in coal during the whole process of adsorption with cumulative gas pressure. A self-developed device was utilized to conduct the adsorption isotherm experiment, and the theoretical method based on the gas state equation was utilized to calculate the real-time permeability of gases during adsorption. The gas flow and velocity at the inlet and outlet were calculated on the basis of the pressure and time change law. Results showed that, during adsorption with accumulated pressure, the average pore pressure of N2 increased, whereas that of CO2 decreased. As cumulative pressure increased, the gas flow at the inlet gradually decreased, whereas that at the outlet increased. The flow and velocity of CO2 at the inlet were the largest, followed by CH4. On the contrary, the flow and velocity of N2 at the outlet were the smallest, followed by CH4. On the basis of the gas flow and velocity at the inlet and outlet, the adsorption amount and permeability of gases in coal were calculated. Gas adsorption isotherm conformed to Langmuir characteristics. Under certain gas pressure, the real-time permeability showed a quadratic form with adsorption amount, and the real-time gas permeability decreased with the increase of cumulative pressure. The real-time permeability of N2 was greater than that of CH4 and CO2, followed by CH4. The research can provide theoretical basis for deep coalbed methane development and carbon sequestration in coal seam, even gas flow in porous media.
      原文链接:
    • NSTL