Optimizing CAPEX and OPEX for High CO2 and H2S Field by Using Mechanistic Corrosion Modelling Approach

2021 ◽  
Author(s):  
Ahmad Fahdlam Saleh ◽  
Muhammad Zaid Kamardin ◽  
Shahrun Nizam Safiin ◽  
Mohd Farizan Ahmad
Keyword(s):  
Corrosion Rate ◽  
Partial Pressure ◽  
Gas Production ◽  
Co2 Corrosion ◽  
Original Design ◽  
Co2 Partial Pressure ◽  
Field Development ◽  
Stage Of Development ◽  
Corrosion Modelling ◽  
Modelling Approach

Abstract The gas contaminants especially CO2 and H2S from the well is a major threat to oil and gas production facilities and pipeline. Developing this type of reservoir cost enormous CAPEX and OPEX due the need for expensive materials or the need of continuous chemical injection. This paper outlines the opportunity of cost optimization for future field development and operational through mechanistic corrosion modelling approach. This method was embedded to an in-house corrosion prediction model that was first developed by collaboration with Ohio University in 2008 with capability to predict corrosion rate for partial pressure more than 20bar of CO2 and up to 1bar of H2S. The model validation was performed based on actual field production operated at 55°C and 22 bar of CO2 partial pressure followed the methodology as outlined in NACE paper C2012-0001449. Upon successful validation, the model has been deployed to assist an Operator of an offshore pipeline in Southeast Asia, operating at 97°C and 17 bar of CO2 partial pressure, to ascertain the risk due to CO2 corrosion and review the original pipeline design adequacy. Subsequently, the model has been utilized for an Operator of onshore facilities in Middle East to address specific issue encountered during the final stage of development for one of the wellpad in which the wells are expected to experience increase of H2S from 100ppm in original design to more than 1000ppm during actual production. This process changes raised a serious concern on the integrity of the materials as potential corrosion issue and the need for corrosion mitigation such as H2S Scavenger injection was not originally considered during early stage of engineering. The corrosion rate from the model has been validated against the intelligent pigging (IP) data and proven to be able to predict corrosion rate with +20% accuracy and more than 99% confidence level for CO2 partial pressure up to 25 bar with the presence of H2S. Based on deployment and utilization of the model, the high confidence in the model ability to accurately predict the corrosion rate will lead to potential CAPEX and OPEX optimization for the field development and during operational stage.

Corrosion Behavior of X70 Pipeline Steel and Corrosion Rate Prediction Under the Combination of Corrosive Medium and Applied Pressure

2017 ◽  
Author(s):  
Kaikai Li ◽  
Wei Wu ◽  
Guangxu Cheng ◽  
Yun Li ◽  
Haijun Hu ◽  
...  
Keyword(s):  
Natural Gas ◽  
Corrosion Rate ◽  
Tensile Stress ◽  
Partial Pressure ◽  
Corrosion Behavior ◽  
Pipeline Steel ◽  
Applied Pressure ◽  
Chloride Concentration ◽  
X70 Pipeline Steel ◽  
Co2 Partial Pressure

Natural gas transmission pipeline is prone to internal corrosion due to the combination of corrosive impurities in the pipe (such as CO2, H2S and chlorides) and applied pressure of the pipeline, which seriously affects the safe operation of the pipeline. In this work, the corrosion behavior of a typical X70 pipeline steel was investigated by using potentiodynamic polarization and electrochemical impendence spectroscopy (EIS). The polarization and EIS data under different CO2 partial pressures (0–1 atm), H2S concentrations (0–150 ppm), chloride concentrations (0–3.5 wt%) and tensile stress (0–400 MPa) were obtained. The results show that corrosion rate increases with the increase of CO2 partial pressure and chloride concentration, respectively, while first increases and then decreases with the increase H2S concentrations. The corrosion rate is less affected by elastic tensile stress. In addition, a quantitative prediction model for corrosion rate of natural gas pipeline based on adaptive neuro-fuzzy inference system (ANFIS) was established by fitting the experimental data which maps the relationship between the key influencing factors (i.e. CO2 partial pressure, H2S concentration, chloride concentration and tensile stress) and the corrosion rate. The prediction results show that the relative percentage errors of the predicted and experimental values are relatively small. The prediction accuracy of the model satisfies the engineering application requirement.

scholarly journals The inhibition performance of mono-ethylene glycol on corrosion rate of x-80 grade carbon steel in saturated brine environment.

2020 ◽  
Vol 1 (1) ◽  
Keyword(s):  
Acetic Acid ◽  
Charge Transfer ◽  
Carbon Steel ◽  
Corrosion Rate ◽  
Ethylene Glycol ◽  
Oil And Gas ◽  
Gas Production ◽  
Electrochemical Measurements ◽  
Co2 Corrosion ◽  
Formation Water

The formation/deposition of hydrate and scale in gas production and transportation pipeline has continue to be a major challenge in the oil and gas industry. Pipeline transport is one of the most efficient, reliable and safer means of transporting petroleum products from the well sites to either the refineries or to the final destinations. Acetic acid (HAc), is formed in the formation water which also present in oil and gas production and transportation processes. Acetic acid aids corrosion in pipelines and in turn aids the formation and deposition of scales which may eventually choke off flow. Most times, Monethylene Glycol (MEG) is added into the pipeline as an antifreeze and anticorrosion agent. Some laboratory experiments have shown that the MEG needs to be separated from unwanted substance such as HAc that are present in the formation water to avoid critical conditions in the pipeline. Internal pipeline corrosion slows and decreases the production of oil and gas when associated with free water and reacts with CO2 and organic acid by lowering the integrity of the pipe. In this study, the effect of Mono-Ethylene Glycol (MEG) and Acetic acid (HAc) on the corrosion rate of X-80 grade carbon steel in CO2 saturated brine were evaluated at 25oC and 80oC using 3.5% NaCl solution in a semi-circulation flow loop set up. Weight loss and electrochemical measurements using the linear polarization resistance (LPR) and electrochemical impedance spectroscope (EIS) were used in measuring the corrosion rate as a function of HAc and MEG concentrations. The results obtained so far shows an average corrosion rate increases from 0.5 to 1.8 mm/yr at 25oC, and from 1.2 to 3.5 mm/yr at 80oC in the presence of HAc. However, there are decrease in corrosion rate from 1.8 to 0.95 mm/yr and from 3.5 to 1.6mm/yr respectively at 25oC and 80oC on addition of 20% and 80% MEG concentrations to the solution. It is also noted that the charge transfer with the electrochemical measurements (EIS) results is the main corrosion controlling mechanism under the test conditions. The higher temperature led to faster film dissolution and higher corrosion rate in the presence of HAc. The EIS results also indicate that the charge transfer controlled behaviour was as a result of iron carbonate layer accelerated by the addition of different concentrations of MEG to the system. Key words: CO2 corrosion, Carbon steel, MEG, HAc, Inhibition, Environment.

scholarly journals USING WIRE BEAM ELECTRODE (WBE) TO EVALUATE THE CORROSION BEHAVIOR OF ND STEEL IN ACID MEDIUM

2020 ◽  
Vol 1 (2) ◽  
pp. 27-30
Author(s):  
Bo Zhao ◽  
Yuxin Yu ◽  
Jing Guo ◽  
Tianyu Zhou ◽  
Shiwen Zou ◽  
...  
Keyword(s):  
Partial Pressure ◽  
Corrosion Behavior ◽  
Ring Structure ◽  
Corrosion Products ◽  
Dew Point ◽  
Co2 Corrosion ◽  
Uniform Corrosion ◽  
Corrosion Morphology ◽  
Co2 Partial Pressure ◽  
Wire Beam Electrode

In this article, wire beam electrode (WBE) was used to evaluate the corrosion behavior of ND steel in environmental acid atmosphere with different partial pressure of CO2. Meanwhile, corrosion products and surface morphology analysis also used to support this research. The results showed that the corrosion behavior began from the edge of droplet in dew point corrosion, and gradually spread to the center of it. The spread speed would be increasing with CO2 partial pressure enhance, which was 24h in 5% CO2 and 4h in 50% CO2. Corrosion current density in the edge of droplet can form the “cathode-anode-cathode ring” structure and disappears gradually as the corrosion time was going. Corrosion morphology observation results showed three ring shapes region and different elemental composition of different corrosion products, which is correspondence with the “cathode-anode We-cathode ring” structure measured in WBE experiments. The results showed that the reaction gradually transferred to the uniform corrosion on electrode surface when the dew point corrosion reaction reaching the late stage. It comes from the dissolution, diffusion and reaction of gaseous corrosion medium of CO2 and O2.

scholarly journals Corrosion Investigation of Commercially Available Linepipe Steel in CO2 Environment

2018 ◽  
Vol 7 (3.32) ◽  
pp. 15
Author(s):  
Muhammad Haris ◽  
Saeid Kakooei ◽  
Mokhtar Che Ismail
Keyword(s):  
Carbon Steel ◽  
Corrosion Rate ◽  
Oil And Gas ◽  
Corrosion Behaviour ◽  
Complex Problem ◽  
Gas Production ◽  
Co2 Corrosion ◽  
Oil And Gas Production ◽  
The Difference ◽  
Co2 Environment

CO2 corrosion has been the most prevalent form of corrosion and is considered as a complex problem in oil and gas production industries. The CO2 in presence of water causes sweet corrosion that is responsible for failure of pipeline during transportation of Oil and Gas. This work studies the corrosion behaviour of carbon steel specimens in CO2 environment at different temperatures but at constant pressure. The effect of CO2 on Carbon Steel specimens (X65, A106) were studied in simulated solution of 3 wt.% NaCl. The specimens were immersed into the CO2 containing solution for 48 hours and corrosion behaviour was investigated by using electrochemical test like Linear Polarization Resistance and Tafel plot. The results indicate that the temperature has an important effect of corrosion rate of carbon Steel in CO2 environment. Corrosion rate of 1.5-2 mm/yr was reported for both steels at lower temperature while at higher temperature the difference can be observed due to difference in protective nature of steels. Similar Corrosion rate around 1.5 -2 mm/yr was observed at 25°C for both A106 and X65 while at 50°C and 75°C the corrosion rate varies significantly 1.5-3 mm/yr and 3.5-6 mm/yr.  

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

Materials ◽  
2018 ◽  
Vol 11 (9) ◽  
pp. 1765 ◽  
Author(s):  
Haitao Bai ◽  
Yongqing Wang ◽  
Yun Ma ◽  
Qingbo Zhang ◽  
Ningsheng Zhang
Keyword(s):  
Carbon Steel ◽  
Corrosion Rate ◽  
Crude Oil ◽  
Partial Pressure ◽  
Initial Period ◽  
Localized Corrosion ◽  
Corrosion Mechanism ◽  
Corrosion Properties ◽  
Co2 Partial Pressure ◽  
Corrosion Scale

The influence of CO2 partial pressure on the corrosion properties, including corrosion rate, morphology, chemical composition, and corrosion depth, of J55 carbon steel in 30% crude oil/brine at 65 °C was investigated. A corrosion mechanism was then proposed based on the understanding of the formation of localized corrosion. Results showed that localized corrosion occurred in 30% crude oil/brine with CO2. The corrosion rate sharply increased as the CO2 partial pressure (P co 2 ) was increased from 0 to 1.5 MPa, decreased from P co 2 = 1.5 MPa to P co 2 = 5.0 MPa, increased again at P co 2 = 5.0 MPa, and then reached a constant value after P co 2 = 9.0 MPa. The system pH initially decreased, rapidly increased, and then stabilized as CO2 partial pressure was increased. In the initial period, the surface of J55 carbon steel in the CO2/30% crude oil/brine mixtures showed intense corrosion. In conclusion, CO2 partial pressure affects the protection performance of FeCO3 by changing the formation of corrosion scale and further affecting the corrosion rate.

ECONOMIC EFFICIENCY OF THE PROJECT “ACQUISITION OF LIFTING UNITS APRS-18 AT NGDU “YAMASHNEFT”

2020 ◽  
Vol 1 (8) ◽  
pp. 80-86
Author(s):  
L. N. KRASNOVA ◽  
◽  
L. V. GUSAROVA ◽  
A. Ya. GAFUROVA ◽  
A. F. ZABBAROVA ◽  
...  
Keyword(s):  
Economic Efficiency ◽  
Oil And Gas ◽  
Effective Field ◽  
Gas Production ◽  
Oil And Gas Production ◽  
Field Development ◽  
Capital Costs ◽  
Oil Reserves ◽  
Stage Of Development ◽  
Goals And Objectives

The article is devoted to evaluating the effectiveness of implementing the APRS-18 lifting unit in order to improve the technology of underground repair of oil wells that have entered the late stage of development. The feasibility of implementing the unit is justified by the current stage of development of PJSC Tatneft and the state of the reserves structure of the developed fields. In conditions when the share of hard-to-recover oil reserves has increased to 86%, effective field development is impossible without the introduction of new equipment and technology. The article highlights the advantages of the APRS-18 lifting unit for repairing deeper wells working on Devon, and outlines the goals and objectives of implementing the unit. The economic efficiency of implementing APRS-18 units in Yamashneft NGDU, which is one of the leading oil and gas production departments in the structure of PJSC Tatneft, is calculated. Risks and uncertainties of the project are considered and identified, and the effectiveness of its implementation is proved at relatively low capital costs

Integrated Subsurface to Surface Modeling to Assess Reservoir Uncertainty Quantification to A Carbonate Reservoir

2020 ◽  
Author(s):  
A. Chaterine
Keyword(s):  
Uncertainty Quantification ◽  
Gas Production ◽  
Carbonate Reservoir ◽  
Production Volume ◽  
Production Forecast ◽  
Uncertainty Range ◽  
Field Development ◽  
Production Forecasting ◽  
Production Scheme ◽  
Rock Compressibility

This study accommodates subsurface uncertainties analysis and quantifies the effects on surface production volume to propose the optimal future field development. The problem of well productivity is sometimes only viewed from the surface components themselves, where in fact the subsurface component often has a significant effect on these production figures. In order to track the relationship between surface and subsurface, a model that integrates both must be created. The methods covered integrated asset modeling, probability forecasting, uncertainty quantification, sensitivity analysis, and optimization forecast. Subsurface uncertainties examined were : reservoir closure, regional segmentation, fluid contact, and SCAL properties. As the Integrated Asset Modeling is successfully conducted and a matched model is obtained for the gas-producing carbonate reservoir, highlights of the method are the following: 1) Up to ± 75% uncertainty range of reservoir parameters yields various production forecasting scenario using BHP control with the best case obtained is 335 BSCF of gas production and 254.4 MSTB of oil production, 2) SCAL properties and pseudo-faults are the most sensitive subsurface uncertainty that gives major impact to the production scheme, 3) EOS modeling and rock compressibility modeling must be evaluated seriously as those contribute significantly to condensate production and the field’s revenue, and 4) a proposed optimum production scenario for future development of the field with 151.6 BSCF gas and 414.4 MSTB oil that yields a total NPV of 218.7 MMUSD. The approach and methods implemented has been proven to result in more accurate production forecast and reduce the project cost as the effect of uncertainty reduction.

Separation of carotid body chemoreceptor responses to O2 and CO2 by oligomycin and by antimycin A

1982 ◽  
Vol 242 (3) ◽  
pp. C200-C206 ◽  
Author(s):  
E. Mulligan ◽  
S. Lahiri
Keyword(s):  
Steady State ◽  
Carbonic Anhydrase ◽  
Partial Pressure ◽  
Carotid Body ◽  
Body Tissue ◽  
Antimycin A ◽  
Tissue Ph ◽  
Co2 Partial Pressure ◽  
O2 Partial Pressure ◽  
Metabolic Hypothesis

The cat carotid chemoreceptor O2 and CO2 responses can be separated by oligomycin and by antimycin A. Both of these agents greatly diminish or abolish the chemoreceptor O2 response but not the nicotine or CO2 responses. After either oligomycin or antimycin, the responses to increases and decreases in arterial CO2 partial pressure (PaCO2) consisted of increases and decreases in activity characterized respectively by exaggerated overshoots and undershoots. These were eliminated by the carbonic anhydrase inhibitor, acetazolamide, suggesting that they resulted from changes in carotid body tissue pH. The steady-state PaCO2 response remaining after oligomycin was no longer dependent on arterial O2 partial pressure (PaO2). All effects of antimycin were readily reversible in about 20 min. The separation of the responses to O2 and CO2 indicates that there may be at least partially separate pathways of chemoreception for these two stimuli. The similarity of the oligomycin and antimycin results supports the metabolic hypothesis of chemoreception.

Sign in / Sign up

Export Citation Format

Share Document