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In this report, a female patient suffering from pigment retention caused by a skin marking pen was elucidated. The patient underwent blepharoplasty 6 months ago and presented with blue-black linear marks at the upper eyelid incision 2 weeks after surgery. Under dermoscopy, scattered pigments were observed to accumulate in the epidermis of the upper eyelid. The patient was diagnosed with iatrogenic tattoo by a surgical marking pen. We chose surgical excision of the skin with the pigmentation. Previous studies have established that the risk of bacterial contamination, contact dermatitis, and allergies may increase with the surgical marking pens, while pigment retention has not yet been mentioned yet. Here, we present a case with a pigment retention in the incision. The selection of the surgical labelling methods and the management of the pigmentation were also addressed. According to our clinical findings, the risk of pigment retention by marking pens needs to be mentioned in the patient’s informed consent. Therefore, the practitioner should ensure that the ink is cleaned by the end of each invasive procedure.

Multi-terminal flexible DC distribution line faults develop rapidly, and power electronic equipment has a poor ability to withstand overcurrent. To solve the aforementioned problem, a DC line unit protection scheme based on improved Grey Slope Relational Analysis (GSRA) of fault currents is proposed to address the issue of achieving a balance between the reliability and speed of relay protection for DC distribution lines. This scheme uses the fault current measured at both ends of the line under various operating conditions, and calculates the correlation between the current at both ends of the positive and negative lines using the slope distance and polarity of the current increments. Based on this, GSRA is used to analyze the correlation of fault signals so that line faults can be eliminated quickly. This protection scheme allows the selectivity of traditional unit protection to be improved. Simulations using PSCAD/EMTDC have shown that this method can achieve fault discrimination and fault pole selection by simultaneously measuring the current at both ends of the line. This fast protection action is not affected by the line distribution capacitance and converter blocking, strong resistance to transition resistance and noise interference, and reliable identification under heavy loads and high-resistance ground faults.

Abstract Sour gas reservoirs have faced critics for environmental concerns and hazards, necessitating a novel outlook to how the produced sour gases could be either utilized or carefully disposed. Over the years of research and practice, several methods of sour gas processing and utilization have been developed, from the solid storage of sulfur to reinjecting the sour gas into producing or depleted light oil reservoir for miscible flooding enhanced oil recovery. This paper seeks to investigate the impact of injection parameters on the performance of sour gas injection for enhance oil recovery. In designing a miscible gas flooding project, empirical correlations are used and the key parameter which impacts the phase behavior is identified to be the minimum miscibility pressure (MMP). A compositional simulator was utilized in this research work to study the effect of injection parameters such as minimum miscibility pressure, acid gas concentration, injection pressure and injection rate on the performance of miscible sour gas injection for enhanced oil recovery. The findings showed that methane concentration had a significant impact on the MMP of the process. Additionally, an increase in acid gas concentration decreases the MMP of the process as a result of an increase in gas viscosity, consequently extending the plateau period resulting in late gas breakthrough and increased overall recovery of the process.

Hydraulic fracturing enables the commercial development of unconventional resources in shales and tight formations. The conductivity and complexity of created fractures are critically dependent on the rheology of fracking fluid and the mechanics properties of rocks. Literatures show that both the rheology of fracturing fluid and fracture propagation dynamics are affected by the temperature of fracturing fluid. Neglecting the temperature transient behaviour may defeat the purpose of fracturing optimization during fracture initiation, propagation, and sand packing. The objective of this paper is to investigate the impact of temperature on fracturing design by studying the transient temperature behaviour across a complex wellbore using numerical modelling by coupling a finite difference heat transfer model with a dynamic fracture propagation model. The study results show that with the injection of cold fracturing fluid, hydraulic fracture propagation is decelerated, and production prediction is thus lessened compared with the case ignoring temperature effect. For multistage fractured wells, fracture geometry enlarges along the fluid flow direction in a horizontal segment. This potentially lowers the cost of hydraulic fracturing designs.

Abstract Less than 10% of oil is usually recovered from liquid-rich shales and this leaves much room for improvement, while water injection into shale formation is virtually impossible because of the extremely low permeability of the formation matrix. Injecting carbon dioxide (CO2) into oil shale formations can potentially improve oil recovery. Furthermore, the large surface area in organic-rich shale could permanently store CO2 without jeopardizing the formation integrity. This work is a mechanism study of evaluating the effectiveness of CO2-enhanced oil shale recovery and shale formation CO2 sequestration capacity using numerical simulation. Petrophysical and fluid properties similar to the Bakken Formation are used to set up the base model for simulation. Result shows that the CO2 injection could increase the oil recovery factor from 7.4% to 53%. In addition, petrophysical characteristics such as in situ stress changes and presence of a natural fracture network in the shale formation are proven to have impacts on subsurface CO2 flow. A response surface modeling approach was applied to investigate the interaction between parameters and generate a proxy model for optimizing oil recovery and CO2 injectivity.

CO2 flooding is an important method for improving oil recovery for reservoirs with low permeability. Even though CO2 could be miscible with oil in regions nearby injection wells, the miscibility could be lost in deep reservoirs because of low pressure and the dispersion effect. Reducing the CO2−oil miscibility pressure can enlarge the miscible zone, particularly when the reservoir pressure is less than the needed minimum miscible pressure (MMP). Furthermore, adding intermediate hydrocarbons in the CO2−oil system can also lower the interfacial tension (IFT). In this study, we used dead crude oil from the H Block in the X oilfield to study the IFT and the MMP changes with different hydrocarbon agents. The hydrocarbon agents, including alkanes, alcohols, oil-soluble surfactants, and petroleum ethers, were mixed with the crude oil samples from the H Block, and their performances on reducing CO2−oil IFT and CO2−oil MMP were determined. Experimental results show that the CO2−oil MMP could be reduced by 6.19 MPa or 12.17% with petroleum ether in the boiling range of 30−60 °C. The effects of mass concentration of hydrocarbon agents on CO2−oil IFT and crude oil viscosity indicate that the petroleum ether in the boiling range of 30−60 °C with a mass concentration of 0.5% would be the best hydrocarbon agent for implementing CO2 miscible flooding in the H Block.

In drilling a deepwater well, the mud density window is narrow, which needs a precise pressure control to drill the well to its designed depth. Therefore, an accurate characterization of annular flow between the drilling riser and drilling string is critical in well control and drilling safety. Many other factors influencing the change of drilling pressure that should be but have not been studied sufficiently. We used numerical method to simulate the process of drill string rotation and vibration in the riser to show that the rotation and transverse vibration of drill string can increase the axial velocity in the annulus, which results in the improvement of the flow field in the annulus, and the effect on pressure loss and its fluctuation amplitude. In addition, there are also multiple secondary flow vortices in the riser annulus under certain eccentricity conditions, which is different from the phenomenon in an ordinary wellbore. The findings of this research are critical in safely controlling well drilling operation in the deepwater environment. [ABSTRACT FROM AUTHOR]

Less than 10% of oil is usually recovered from liquid-rich shales and this leaves much room for improvement, while water injection into shale formation is virtually impossible because of the extremely low permeability of the formation matrix. Injecting carbon dioxide (CO2) into oil shale formations can potentially improve oil recovery. Furthermore, the large surface area in organicrich shale could permanently store CO2 without jeopardizing the formation integrity. This work is a mechanism study of evaluating the effectiveness of CO2-enhanced oil shale recovery and shale formation CO2 sequestration capacity using numerical simulation. Petrophysical and fluid properties similar to the Bakken Formation are used to set up the base model for simulation. Result shows that the CO2 injection could increase the oil recovery factor from 7.4% to 53%. In addition, petrophysical characteristics such as in situ stress changes and presence of a natural fracture network in the shale formation are proven to have impacts on subsurface CO2 flow. A response surface modeling approach was applied to investigate the interaction between parameters and generate a proxy model for optimizing oil recovery and CO2 injectivity. [ABSTRACT FROM AUTHOR]

On the basis of the wellbore and reservoir heat-transfer process during deepwater drilling, a heat-transfer model between wellbore and formation is built up for two different conditions: without riser and with riser. Wellbore and formation temperature distributions under different drilling-fluid-injection temperatures, flow rates, circulating times, and drilling depths are simulated by use of this model. Taking the hydrate-phase equilibrium into consideration, a possible region of hydrate-formation dissociation is analyzed, and effective methods are proposed to control the hydrate dissociation. The results indicate that, during shallow formation drilling, the increase of drilling-fluid flow rate will cause the wellbore temperature to rise, but below the hydratedissociation temperature in the whole process; during deep-formation drilling, drilling fluid is heated, and the heat is transferred from the deeper formation to the shallower formation through fluid circulation. Thus, the hydrate-reservoir temperature increases gradually along the wellbore radial direction. Hydrates will dissociate after the hydrate equilibrium temperature is reached; this may cause wellbore collapse or methane leak from the reservoir and result in disaster. To control hydrate dissociation during deepwater drilling, attention should be paid to the period of deep-formation drilling. Sensitivity studies indicate that the risk of hydrate dissociation rises as the drilling-fluidinjection temperature, flow rate, and circulating time increase. [ABSTRACT FROM AUTHOR]

Hydraulic fracturing has been applied as an effective method to increase gas production from shale formations; however, this method has also raised concerns about its adverse impacts on environment. For example, in the Marcellus shale formation, some measured radon-gas concentrations exceeded the safe standard. Therefore, it is important to quantitatively evaluate radon concentration from fractured wells. However, existing researches have not successfully conducted a systematic and predictive study on the relationship between shale gas production and radon concentration at the wellhead of a hydraulically fractured well. To address this issue and quantitatively determine the radon concentration, we present the mechanisms of radon-gas generation and releasing, and conducted numerical simulations on its transport process in the subsurface formation system. The concentration of radon in produced gas is related with the original sources where the natural gas is extracted. Radon, generated from the radium alpha decay process, is trapped in pore spaces before the reservoir development. With the fluid flowing through the subsurface network, released radon will move to surface with the produced streams such as natural gas and flowback water. Our study shows that the radon concentration at wellhead could be significant. Influential factors such as natural-fracture-network properties, formation petrophysical parameters, and fracture dimension are investigated with sensitivity studies through numerical simulations. Analysis results suggest that radon wellhead concentration is strongly related with production rate. Thus, careful production design and protection are necessary to reduce radon hazard regarding the public and environmental impact. [ABSTRACT FROM AUTHOR]

Permanent downhole-pressure and -temperature gauges have been installed in many intelligent wells worldwide, providing high-resolution and precision surveillance data about the performance of wells and reservoirs. Compared with the pressure data, the temperature data have been underused in the petroleum industry. In this paper, we first examine the measured downhole-temperature variation caused by the Joule-Thomson effect and infer the true reservoir temperature and the skin history from the temperature data. An analytical relationship between the temperature data and the skin is presented. Through the use of this relationship, many purposeful surveillance studies, such as monitoring the skin change of the well, can be conducted. Examples of such studies will be provided and discussed using some deepwater-field data. Furthermore, the downhole temperature can be used to detect whether water breakthrough occurs by means of matrix or fracture through use of the thermal retardation factor. When coupled with the production data and pressure-falloff (PFO) tests, the downhole-temperature data can be used to estimate the water-breakthrough time. The application of this analysis is of practical interest for subsea-well development because of the prohibitive costs and high risks of production logging. [ABSTRACT FROM AUTHOR]

Permanent-downhole-gauge (DHG) technology has been used widely in deepwater-reservoir development in the last decade and is playing an increasingly significant role in real-time reservoir/well surveillance and management. Tidal signals extracted from this highly accurate and precise device can be used for reservoir characterization such as monitoring the changes of saturations and estimating rock/pore compressibility. Most previous works have treated tidal signals as pressure "noise," and little has been discussed on how to use tidal information in reservoir characterization. This paper will address how to use the fast Fourier transform (FFT) to extract tidal signals and the theories and methods for processing the signal to achieve reservoir characterization. In addition, a couple of examples from a deepwater field will be discussed to illustrate how to use tidal information to estimate pore compressibility, monitor dynamic fluid-saturation change, and detect the presence of a secondary gas cap. This paper will show that FFT is a fast and reliable method for processing the DHG pressure data for tidal signals that can be used for reservoir characterization in multiple dimensions. Furthermore, the results (pore compressibility and saturation) obtained from the tidal signals are unique because they cannot be obtained in the laboratory, by simulation, or by direct measurement because of the scale affected by tides. [ABSTRACT FROM AUTHOR]

In order to develop and utilize Lentinus edodes protein, the effect of glutamine transaminase (TGase) cross-linking on the physicochemical and processing characteristics of L. edodes protein was studied. The results showed that the addition of 0%–20% TGase gradually reduced the contents of total thiol, free thiol and β-sheet of L. edodes protein, while the fluorescence intensity, particle size, β-turn content and surface hydrophobicity showed a trend of initially increasing and then decreasing. As the shear rate increased, the shear stress of the protein increased and the apparent viscosity decreased, indicating that TGase cross-linking promoted the generation of macromolecular polymers. In addition, the cross-linked protein exhibited a dense texture similar to that of the original protein, indicating the formation of a stable three-dimensional network structure. As the addition level of TGase increased from 4% to 12%, the protein network structure became increasingly dense. Moreover, an appropriate amount of TGase significantly improved the solubility, emulsifying properties, thermal stability, and oil-holding capacity of L. edodes protein. These results indicate that TGase cross-linking improves the physicochemical and processing properties of L. edodes protein to varying degrees.