scholarly journals Emulsion Characterization of the Heavy Oil-Alkaline Water System in Alkaline Flooding Mechanism Investigation Using a Combination of Modified Bottle Test and Sandpack Flooding

2021 ◽  
Vol 9 ◽  
Author(s):  
Zhiyu Xi ◽  
Na Jia ◽  
Ezeddin Shirif
Keyword(s):  
Oil Recovery ◽  
Material Balance ◽  
Water System ◽  
Test Method ◽  
Alkaline Solutions ◽  
Driving Mechanism ◽  
Volume Distribution ◽  
Modified Method ◽  
Bottle Test ◽  
Reservoir Conditions

Due to the diversity of alkali categories and reservoir conditions, the varied oil recovery driving mechanism of alkaline flooding is subjected to different types of emulsion generation. In this study, a modified bottle test method that assesses major emulsion type formation for preliminary prediction of alkaline flooding performance in oil recovery is introduced. The modified method considers the necessary energy input required for mixing immiscible bulk phases at low interfacial tension (IFT) regions to improve the representativity of emulsion formation in the bottle test to that of in porous media. To accurately evaluate the emulsion type and phase volume distribution from the bottle test, each emulsion phase after aging in the test bottle was sampled and its water content was measured through Karl Fischer titration. Afterward, material balance calculations other than pure volume observation were applied to quantify the emulsion volume and determine the major emulsion type formation. It is found that the majority of emulsion effluent type from the sandpack flooding test were in agreement with the bottle test forecast which proved the feasibility of the modified bottle test method. The statistically optimized experimental designs were implemented due to the simplicity of the new bottle test method and it considerably cut the time expense regarding the alkaline flooding performance prediction. The high versatility of the modified bottle test ensures that the alkali usage is not limited to the inorganic alkalis mentioned in this study; other type of alkaline solutions can also be used for further expanding the scope of its application.

How Does EOR Polymer Impact Scale Control During ASP Flooding?

2021 ◽  
Author(s):  
Ya Liu ◽  
Rebecca Vilain ◽  
Dong Shen
Keyword(s):  
Oil Recovery ◽  
Synergistic Effects ◽  
Oil And Gas Industry ◽  
Scale Formation ◽  
Test Method ◽  
Scale Inhibitor ◽  
Acrylic Copolymer ◽  
Asp Flooding ◽  
Bottle Test ◽  
The Impact

Abstract Polymer based enhanced oil recovery (EOR) technology has drawn more and more attention in the oil and gas industry. The impacts of EOR polymer on scale formation and control are not well known yet. This research investigated the impacts of EOR polymer on calcite scale formation with and without the presence of scale inhibitors. Seven different types of scale inhibitors were tested, including four different phosphonate inhibitors and three different polymeric inhibitors. Test brines included severe and moderate calcite scaling brines. The severe calcite brine is to simulate alkaline surfactant polymer (ASP) flooding conditions with high pH and high carbonate concentration. The test method used was the 24 hours static bottle test. Visual observation and the residual calcium (Ca2+) concentration determination were conducted after bottle test finished. It was found that EOR polymer can serve as a scale inhibitor in moderate calcite scaling brines, although the required dosage was significantly higher than common scale inhibitors. Strong synergistic effects were observed between EOR polymer and phosphonate scale inhibitors on calcite control, which can significantly reduce scale inhibitor dosage and provides a solution for calcite control in ASP flooding. The impact of EOR polymer on polymeric scale inhibitors varied depending on polymer types. Antagonism was observed between EOR polymer and sulfonated copolymer inhibitor, while there was weak synergism between EOR polymer and acrylic copolymer inhibitors. Therefore, when selecting scale inhibitors for polymer flooding wells in the future, the impact of EOR polymer on scale inhibitor performance should be considered.

Effects of Imbibition During Well Shut-In on Ultimate Shale Oil Recovery: A Numerical Study

2021 ◽  
Author(s):  
Nur Wijaya ◽  
James Sheng
Keyword(s):  
Hydraulic Fracturing ◽  
Oil Recovery ◽  
Numerical Study ◽  
Extended Period ◽  
Strong Relationship ◽  
Driving Mechanism ◽  
Shale Oil ◽  
Probabilistic Forecasting ◽  
Reservoir Conditions ◽  
Shale Oil Reservoirs

Abstract Shale wells are often shut-in after hydraulic fracturing is finished. Shut-in often lasts for an extended period in the perceived hope to improve the ultimate oil recovery. However, current literature does not show a strong consensus on whether shut-in will improve the ultimate oil recovery. Because of the delayed production, evaluating the benefits of shut-in in improving the ultimate oil recovery is crucial. Otherwise, shut-in would merely delay the production and harm the economic performance. This paper uses a numerical flow-geomechanical modeling approach to investigate the effect of imbibition on shut-in potentials to improve the ultimate oil recovery. This paper proposes that imbibition is one of the strongly confounding variables that cause the mixed conclusions in the related literature. The investigation methodology involves probabilistic forecasting of three reservoir realization models validated based on the same field production data. Each of the models represents different primary recovery driving mechanism, such as imbibition-dominant and compaction-dominant recovery. A parametric study is conducted to explore and identify the specific reservoir conditions in which shut-in tends to improve the shale oil recovery. Ten reservoir parameters which affect the imbibition strength are studied under different shut-in durations. Comparison among the three models quantitatively demonstrates that shut-in tends to improve the ultimate oil recovery only if the shale reservoir demonstrates imbibition-dominant recovery. A first-pass economic analysis also suggests that when the shale oil reservoirs demonstrate such an imbibition-dominant recovery, shut-in tends to not only improve the ultimate oil recovery, but also the NPV. A correlation among ultimate oil recovery, flowback efficiency, and NPV also shows that there is no strong relationship between flowback efficiency and ultimate oil recovery. This study is one of the first to emphasize the importance of quantifying the imbibition strength and its contribution in helping recover the shale oil for optimum flowback framework and shale well shut-in design after hydraulic fracturing.

The Influence of Turbulence (or Hydrodynamic Effects) on Strontium Sulphate Scale Formation and Inhibitor Performance

2014 ◽  
Author(s):  
Clare Johnston ◽  
Louise Sutherland
Keyword(s):  
Barium Sulphate ◽  
Test Methods ◽  
Standard Test ◽  
Field Application ◽  
Scale Formation ◽  
Test Method ◽  
Scale Inhibitor ◽  
Modified Method ◽  
Bottle Test ◽  
The Impact

Abstract Inorganic scale (carbonate, sulphate and sulphides) formation can be predicted from thermodynamic models and over recent years better kinetic data has improved the prediction of such scales in field conditions. However these models have not been able to predict the observed deposition where flow disturbances occur, such as at chokes, tubing joints, gas lift valves and safety valves. This can lead to unexpected failures of critical equipment such as downhole safety valves (DHSV’s), and operational issues such as failure to access the well for coiled tubing operations due to tubing restrictions. In recent years it has been recognised that the turbulence found at these locations increases the likelihood of scale formation and experiments have been able to demonstrate that increased turbulence also impacts the minimum scale inhibitor concentration required to prevent scale. One of the industry standard test methods used to screen inhibitors for sulphate scale inhibition is the static bottle test. In this paper the ‘static’ bottle test method is modified to investigate the effects of increasing levels of turbulence on the formation of strontium sulphate scale at a fixed brine composition. Using this modified method it has been possible to demonstrate the impact of varying turbulence on the performance of two common generic types of scale inhibitor (phosphonate and vinyl sulphonate co-polymer). Data on the mass of scale formed, scale morphology using SEM imaging and inhibitor efficiency will be linked to degree of turbulence and scale inhibitor functionality (nucleation inhibition vs. crystal growth retardation). This study builds on the previously published10 findings for barium sulphate which showed phosphonates were less affected by turbulent conditions by carrying out similar tests on strontium sulphate. A clear mechanistic conclusion can now be drawn for sulphate scale formation and inhibition under increasingly turbulent conditions. The findings from this study have a significant impact on the methods of screening scale inhibitors for field application that should be utilised and development of suitable inhibitors that perform better under higher shear conditions.

scholarly journals Experimental study of the supercritical CO 2 diffusion coefficient in porous media under reservoir conditions

2019 ◽  
Vol 6 (6) ◽  
pp. 181902 ◽  
Author(s):  
Junchen Lv ◽  
Yuan Chi ◽  
Changzhong Zhao ◽  
Yi Zhang ◽  
Hailin Mu
Keyword(s):  
Porous Media ◽  
Diffusion Coefficient ◽  
Oil Recovery ◽  
Carbon Capture ◽  
Carbon Capture And Storage ◽  
Elevated Pressure ◽  
Experimental Results ◽  
Saturated Porous Media ◽  
Reservoir Conditions ◽  
The Impact

Reliable measurement of the CO 2 diffusion coefficient in consolidated oil-saturated porous media is critical for the design and performance of CO 2 -enhanced oil recovery (EOR) and carbon capture and storage (CCS) projects. A thorough experimental investigation of the supercritical CO 2 diffusion in n -decane-saturated Berea cores with permeabilities of 50 and 100 mD was conducted in this study at elevated pressure (10–25 MPa) and temperature (333.15–373.15 K), which simulated actual reservoir conditions. The supercritical CO 2 diffusion coefficients in the Berea cores were calculated by a model appropriate for diffusion in porous media based on Fick's Law. The results show that the supercritical CO 2 diffusion coefficient increases as the pressure, temperature and permeability increase. The supercritical CO 2 diffusion coefficient first increases slowly at 10 MPa and then grows significantly with increasing pressure. The impact of the pressure decreases at elevated temperature. The effect of permeability remains steady despite the temperature change during the experiments. The effect of gas state and porous media on the supercritical CO 2 diffusion coefficient was further discussed by comparing the results of this study with previous study. Based on the experimental results, an empirical correlation for supercritical CO 2 diffusion coefficient in n -decane-saturated porous media was developed. The experimental results contribute to the study of supercritical CO 2 diffusion in compact porous media.

Influences of eccentricity ratio on the internal flow and cavitation characteristics of progressing cavity pump

2021 ◽  
pp. 095440622199840
Author(s):  
Yiran Wang ◽  
Xiaodong Yu ◽  
Xiaoxiao Han ◽  
Hao Yan ◽  
Qiang Li ◽  
...  
Keyword(s):  
Internal Flow ◽  
Test Method ◽  
Volume Distribution ◽  
Eccentricity Ratio ◽  
Eccentric Rotation ◽  
Optimal Value ◽  
Pump Test ◽  
Value Range ◽  
Contrast Analysis ◽  
Volume Efficiency

A Progressing Cavity Pump (PCP) works by forming a progressive seal cavity through the eccentric rotation of rotor. PCP parameters, such as eccentricity ratio [Formula: see text], can influence its performance and cavitation characteristics. The internal correlation among clearance fluid, cavitation characteristics, and pump performance should be explored to reveal the variation laws of internal flow and cavitation characteristics in PCP under different [Formula: see text]. In this study, a contrast analysis on external characteristics (e.g. volume efficiency) of pump with different eccentricity ratios was carried out by combining an RNG [Formula: see text] turbulence model based on Singhal full-cavitation model and the model pump test method. Moreover, gas volume distribution of PCP was analyzed and the optimal value range of eccentricity ratio was proposed. Results demonstrate that the axial force and axial power of PCP basically remain the same, volume efficiency increases, and cavitation performance decreases with the increase of [Formula: see text], and the optimal value for [Formula: see text] ranges from 0.17 to 0.24. In addition, a revised NPSHQ is proposed to quantify the cavitation characteristics of PCP.

Application of Hybrid Biosystems for Stimulation of Oil Production

2021 ◽  
Author(s):  
Baghir Alakbar Suleimanov ◽  
Sabina Jahangir Rzayeva ◽  
Ulviyya Tahir Akhmedova
Keyword(s):  
Oil Recovery ◽  
Single Phase ◽  
Experimental Studies ◽  
Oil Production ◽  
Pore Channel ◽  
Subcritical Region ◽  
Slippage Effect ◽  
Liquid Systems ◽  
Reservoir Conditions

Abstract Microbial enhanced oil recovery is considered to be one of the most promising methods of stimulating formation, contributing to a higher level of oil production from long-term fields. The injection of bioreagents into a reservoir results in the creation of oil-dicing agents along with significant amount of gases, mainly carbon dioxide. In early, the authors failed to study the preparation of self-gasified biosystems and the implementation of the subcritical region (SR) under reservoir conditions. Gasified systems in the subcritical phase have better oil-displacing properties than non-gasified systems. The slippage effect determines the behavior of gas–liquid systems in the SR under reservoir conditions. Slippage occurs more easily when the pore channel has a smaller average radius. Therefore, in a heterogeneous porous medium, the filtration profile of gasified liquids in the SR should be more uniform than for a degassed liquid. The theoretical and practical foundations for the preparation of single-phase self-gasified biosystems and the implementation of the SR under reservoir conditions have been developedSR under reservoir conditions. Based on experimental studies, the superior efficiency of oil displacement by gasified biosystems compared with degassed ones has been demonstrated. The possibility of efficient use of gasified hybrid biopolymer systems has been shown.

scholarly journals A new slick water system for hydraulic fracturing in tight reservoir to enhance imbibition oil recovery

2021 ◽  
Vol 303 ◽  
pp. 01001
Author(s):  
Yu Haiyang ◽  
Ji Wenjuan ◽  
Luo Cheng ◽  
Lu Junkai ◽  
Yan Fei ◽  
...  
Keyword(s):  
Contact Angle ◽  
Interfacial Tension ◽  
Hydraulic Fracturing ◽  
Oil Recovery ◽  
Water System ◽  
Natural Fracture ◽  
Fracturing Fluid ◽  
The Core ◽  
Ultralow Permeability

In order to give full play to the role of imbibition of capillary force and enhance oil recovery of ultralow permeability sandstone reservoir after hydraulic fracturing, the mixed water fracture technology based on functional slick water is described and successfully applied to several wells in oilfield. The core of the technology is determination of influence factors of imbibition oil recovery, the development of new functional slick water system and optimization of volume fracturing parameters. The imbibition results show that it is significant effect of interfacial tension, wetting on imbibition oil recovery. The interfacial tension decreases by an order of magnitude, the imbibition oil recovery reduces by more than 10%. The imbibition oil recovery increases with the contact angle decreasing. The emulsifying ability has no obvious effect on imbibition oil recovery. The functional slick water system considering imbibition is developed based on the solution rheology and polymer chemistry. The system has introduced the active group and temperature resistant group into the polymer molecules. The molecular weight is controlled in 1.5 million. The viscosity is greater than 2mPa·s after shearing 2h under 170s-1 and 100℃. The interfacial tension could decrease to 10-2mN/m. The contact angle decreased from 58° to 22° and the core damage rate is less than 12%. The imbibition oil recovery could reach to 43%. The fracturing process includes slick water stage and linear gel stage. 10% 100 mesh ceramists and 8% temporary plugging agents are carried into the formation by functional slick water. 40-70 mesh ceramists are carried by linear gel. The liquid volume ratio is about 4:1 and the displacement is controlled at 10-12m3/min. The sand content and fracturing fluid volumes of single stage are 80m3 and 2500 m3 respectively. Compared with conventional fracturing, due to imbibition oil recovery, there is only 25% of the fracturing fluid flowback rate when the crude oil flew out. When the oil well is in normal production, about 50% of the fracturing fluid is not returned. It is useful to maintain the formation energy and slow down the production decline. The average cumulative production of vertical wells is greater than 2800t, and the effective period is more than 2 years. This technology overcoming the problem of high horizontal stress difference and lack of natural fracture has been successfully applied in Jidong Oilfield ultralow permeability reservoir. The successful application of this technology not only helps to promote the effective use of ultralow permeability reservoirs, but also helps to further clarify the role of imbibition recovery, energy storage and oil-water replacement mechanism.

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