Effect of CO2 Partial Pressure on the Corrosion Behavior of J55 Carbon Steel in 30% Crude Oil/Brine Mixture

Bai, Haitao; Wang, Yongqing; Ma, Yichen; Zhang, Qingbo; Zhang, Ningsheng

doi:10.3390/ma11091765

Cited by 34 publications

(9 citation statements)

References 30 publications

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“…However, after years of exploitation, the oil and gas production in the reservoir declines to result in a major economic challenge for the oil companies. The injection of CO 2 at high pressure into the wellbore is an effective method to increase the oil fields lifetime [ 1 , 2 , 3 , 4 ]. This process is usually referred to as carbon dioxide flooding enhanced oil recovery (CO 2 -EOR).…”

Section: Introductionmentioning

confidence: 99%

Effect of CO2 Partial Pressure on the Corrosion Inhibition of N80 Carbon Steel by Gum Arabic in a CO2-Water Saline Environment for Shale Oil and Gas Industry

et al. 2020

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The effect of CO2 partial pressure on the corrosion inhibition efficiency of gum arabic (GA) on the N80 carbon steel pipeline in a CO2-water saline environment was studied by using gravimetric and electrochemical measurements at different CO2 partial pressures (e.g., PCO2 = 1, 20 and 40 bar) and temperatures (e.g., 25 and 60 °C). The results showed that the inhibitor efficiency increased with an increase in inhibitor concentration and CO2 partial pressure. The corrosion inhibition efficiency was found to be 84.53% and 75.41% after 24 and 168 h of immersion at PCO2 = 40 bar, respectively. The surface was further evaluated by scanning electron microscopy (SEM), energy dispersive spectroscopy (EDS), grazing incidence X-ray diffraction (GIXRD), and X-ray photoelectron spectroscopy (XPS) measurements. The SEM-EDS and GIXRD measurements reveal that the surface of the metal was found to be strongly affected by the presence of the inhibitor and CO2 partial pressure. In the presence of GA, the protective layer on the metal surface becomes more compact with increasing the CO2 partial pressure. The XPS measurements provided direct evidence of the adsorption of GA molecules on the carbon steel surface and corroborated the gravimetric results.

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Section: Introductionmentioning

confidence: 99%

Effect of CO2 Partial Pressure on the Corrosion Inhibition of N80 Carbon Steel by Gum Arabic in a CO2-Water Saline Environment for Shale Oil and Gas Industry

et al. 2020

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“…After the damage simulation, the core was taken out and displaced with nitrogen, and the value of stable gas-measured permeability was recorded. The permeability values at the contaminated end surface and at the cutting surface 0.7 cm from the end were measured to evaluate the penetration depth of drilling fluid.Finally, the core surfaces before and after the contamination as well as after the removal of the contaminated section were observed by the optical digital microscope to capture plane view image and three-dimensional (3D) image using a visual image processing method (Bai et al., 2018), and compared to further determine the degree of damage.…”

Section: Methodsmentioning

confidence: 99%

A laboratory approach to predict the water-based drill-in fluid damage on a shale formation

Wang

et al. 2020

Energy Exploration & Exploitation

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Shale gas production after drill-in, completion, and hydraulic fracturing is strongly affected by formation damage. In order to determine the damage mechanisms for nonmarine shale reservoir, a series of assessments of sensitivity damage, water block damage, water-based drill-in fluids damage, and water damage to gas diffusion on 20 shale samples obtained from Chang 7 Formation were conducted and analyzed. Results indicate that, in the Chang 7 Formation shale, there is extremely strong stress sensitivity and moderately weak water sensitivity damage. Although the liquid phase invasion depth is shallow and the water block damage is limited, the liquid phase and solid particles would enter the microfractures in the reservoir.The P-1 water-based drill-in fluid is compatible with the Chang 7 Formation shale reservoir which can meet the requirement of Chang 7 Formation shale damage controlling, the effect of water-based drill-in fluid on wellbore stability should be paid more attention. The diffusion coefficient of the shale decreases with the presence of water.A systematic damage evaluation method of working fluid considering the multi-mechanism and multi-scale mass transfer process of shale gas is needed to establish.

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“…After the experiment, the corroded samples were photographed to record the surface variations and then immersed in an acid solution (500 mL of HCl and 3.5 g hexamethylenamine diluted with water to 1000 mL) for 10 min to remove product films [ 4 ]. The samples were placed on absolute ethanol for washing two times until the acid cleaning solution on the surface was completely removed.…”

Section: Methodsmentioning

confidence: 99%

“…Thus, many studies have investigated CO 2 corrosion based on these factors. Bai et al [4] investigated the influence of CO 2 partial pressure on the properties of J55 carbon steel in 30% crude oil/brine at 65 • C. The corrosion rate significantly increases as the CO 2 partial pressure increases from 0 to 1.5 MPa and decreases from 1.5 to 5 MPa, and the surface of J55 carbon steel is covered by FeCO 3 and CaCO 3 . The CO 2 partial pressure changes the system pH and CO 2 solubility in crude oil, which further affects the formation and protection performance of the corrosive film.…”

Section: Introductionmentioning

confidence: 99%

Experimental Study on Corrosion Performance of Oil Tubing Steel in HPHT Flowing Media Containing O2 and CO2

Dou

Cheng

et al. 2020

Materials

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The high pressure and high temperature (HPHT) flow solution containing various gases and Cl− ions is one of the corrosive environments in the use of oilfield tubing and casing. The changing external environment and complex reaction processes are the main factors restricting research into this type of corrosion. To study the corrosion mechanism in the coexistence of O2 and CO2 in a flowing medium, a HPHT flow experiment was used to simulate the corrosion process of N80 steel in a complex downhole environment. After the test, the material corrosion rate, surface morphology, micromorphology, and corrosion product composition were tested. Results showed that corrosion of tubing material in a coexisting environment was significantly affected by temperature and gas concentration. The addition of O2 changes the structure of the original CO2 corrosion product and the corrosion process, thereby affecting the corrosion law, especially at high temperatures. Meanwhile, the flowing boundary layer and temperature changed the gas concentration near the wall, which changed the corrosion priority and intermediate products on the metal surface. These high temperature corrosion conclusions can provide references for the anticorrosion construction work of downhole pipe strings.

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Effect of CO2 Partial Pressure on the Corrosion Behavior of J55 Carbon Steel in 30% Crude Oil/Brine Mixture

Cited by 34 publications

References 30 publications

Effect of CO2 Partial Pressure on the Corrosion Inhibition of N80 Carbon Steel by Gum Arabic in a CO2-Water Saline Environment for Shale Oil and Gas Industry

Effect of CO2 Partial Pressure on the Corrosion Inhibition of N80 Carbon Steel by Gum Arabic in a CO2-Water Saline Environment for Shale Oil and Gas Industry

A laboratory approach to predict the water-based drill-in fluid damage on a shale formation

Experimental Study on Corrosion Performance of Oil Tubing Steel in HPHT Flowing Media Containing O2 and CO2

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