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Collaborating Authors
Results
The Selection of Corrosion Inhibitors under Oil/Water/Gas Flow Conditions in Deep Offshore Catenary Risers
Kang, Cheolho (Det Norske Veritas USA, Incorporated) | Tummala, Kavitha (Det Norske Veritas USA, Incorporated) | Rhodes, Jesse (Det Norske Veritas USA, Incorporated) | Magalhae, Alvaro Augusto Oliveira (Petrobras)
ABSTRACT Multiphase flow characteristics can be altered with the change of pipeline topography in deep offshore oil and gas production. The increase of corrosion rate and decrease of inhibitor performance in the risers can occur due to the change of multiphase flow characteristics (e.g. severe slugging). For the simulation of offshore flow lines and risers, the experiments were carried out in a 44 m long industrial scale multiphase flow loop equipped with three different pipeline inclinations of 0, 3 and 45 degrees. The effectiveness of three commercial corrosion inhibitors were analyzed using 25 cP oil at 20% water cut with three different gas velocities (0.7 m/s, 3 m/s, and 6 m/s). All tests were carried out at a liquid velocity of 1.5 m/s, a system pressure of 6 bar (76 psig) using carbon dioxide gas as the gas phase, and a temperature of 50°C. Also, the effect of inclination on the flow characteristics (e.g. flow pattern) and their subsequent effect on corrosion rates are described. The results indicated that severe pitting corrosion was noticed in the 3 and 45° weight loss coupons for baseline testing. Severe slugging and high slug frequency were seen in 45 degree upward flowing conditions. The tests differentiated between three corrosion inhibitors. In most of testing conditions, high inhibitor concentration was required to achieve the target corrosion rate.
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (1.00)
Development of Continuous Application Based Corrosion Inhibitors to Mitigate the Problems Caused by Top of the Line Corrosion in Upstream Oil and Gas Industry
Narasaiah, Vijaya Kumar (Nalco Water India Limited) | Gangar, Mitesh Laxmichand (Nalco Water India Limited) | Garg, Gaurav (Nalco Water India Limited) | Monk, Keith (Nalco Energy Services)
ABSTRACT In multiphase wet gas systems with stratified flow, condensation of water and/or hydrocarbon occurs at the top of the line because of a temperature gradient between the internal and external environments of the pipeline. Acidic gases such as carbon dioxide, hydrogen sulfide, and even organic acids may be present in such systems, and they cause a reduction of pH because of their dissolution in the condensed water. In the absence of any buffering agents, this condensed water can cause significant corrosion between the 10 o?clock to 2 o?clock positions, and this deterioration is formally described as top of the line corrosion (TLC). Conventional corrosion inhibitors are transported to the pipeline surface through the produced fluids, and in the absence of turbulence in the pipeline, the effectiveness of conventional continuous inhibitors at the top of the line is drastically reduced. The metal remains unprotected and exposed to these corrosive species resulting in severe damage. Corrosion at the top of the line can severely hamper the safe operation of assets as well as decrease their life of operation, and hence, there is a need for effective chemistries which will mitigate the corrosion issues at the top of the line. This paper describes the development of new, continuous application based, top of the line corrosion inhibitors utilizing an in-house condensation rig for screening applicable candidates. Progress on the development and understanding of applicable chemistries for several generations of TLC inhibitor products will be discussed.
ABSTRACT Top of line corrosion loop experiments have been performed at 85 °C with 10 bar CO2 and 0.1 – 1 mbar H2S. The acetic acid content was varied between 360 and 3030 mg/kg acetic acid in the condensed water. Under these conditions corrosion products consisting mainly of iron carbonate were formed on the steel surface where condensation occurred. This is in contrast to previous experiments under similar conditions at 25 °C, where the corrosion products contained mostly iron sulfide due to the slow precipitation of iron carbonate at low temperature. The top of line corrosion rate increased strongly with the amount of acetic acid in the condensed water. Top of line corrosion is limited by the amount of iron that can dissolve in the condensed water, and acetic acid increases the corrosion rate because it increases the solubility of iron in the condensing water. The experimental conditions were simulated by calculations using a chemical solubility software package. The calculations showed that the solubility of iron carbonate increases with increasing acetic acid content. The calculated values fitted well with the measured values in the experiments. The calculations also showed that the saturation ratio for iron carbonate is significantly higher than for iron sulfide under these conditions. The small amounts of H2S in these experiments did not have a notable effect on the resulting corrosion rate under these conditions at 85 °C, where iron carbonate is the main corrosion product.
New Biofouling Control Program for Open Recirculating Cooling Water System with Refrigerator/Chiller to Reduce Operating and Maintenance Costs of the System.
Nagai, N (Kurita Water Industries Limited) | Morita, A. (Kurita Water Industries Limited) | Tsunoda, K. (Kurita Water Industries Limited) | Emori, K. (Kurita Water Industries Limited)
ABSTRACT Various biofouling control chemicals have been commonly applied to open recirculating cooling water systems with refrigerators and/or chillers at industrial factories and buildings to keep system performance at higher level and to reduce the risk of waterborne deceases such as Legionnaire’s disease. The biofouling control chemicals can be classified to two types of oxidizing and non-oxidizing, but deterioration of chemicals’ performance can’t be evitable due to active ingredients’ decomposition and/or adsorption to other substances. New biofouling control program has been developed which consists of three technologies, the advanced stabilized oxidizing biocide, regeneration of active ingredients, and efficiency monitoring for refrigerator/chiller. Because the new program has the superior performance to suppress the biofouling in the whole system including refrigerator, chiller, recirculating lines and cooling tower, the increase of electricity consumption can be depressed and the time interval of system cleaning can be prolonged. Field applications show the improvement of energy efficiency of the refrigerators/chillers up to 10% compared to the previous chemicals treatments. One case at an electric industry factory shows 9% of energy efficiency improvement that can be estimated to the decrease of CO2 emission of 1,900 t.
- North America > United States > Texas (0.20)
- Asia > Japan (0.17)
- Materials (1.00)
- Water & Waste Management > Water Management > Water Supplies & Services (0.73)
Evaluation of the Seabed Temperature Corrosion and Sulfide Stress Cracking Resistance of Weldable Martensitic 13% Chromium Stainless Steel
Dent, Philip (Exova (UK) Limited) | Fowler, Chris (Exova (UK) Limited) | Walters, Matthew (The University of Birmingham) | Connolly, Brian (The University of Birmingham) | Ueda, Masakatsu (Nippon Steel & Sumitomo Metal Corporation) | Amaya, Hisashi (Nippon Steel & Sumitomo Metal Corporation) | Takabe, Hideki (Nippon Steel & Sumitomo Metal Corporation)
ABSTRACT Weldable Martensitic 13% Chromium Stainless Steels (WMSS) are used for mildly sour welded flow-lines in the oil and gas industry, as an alternative to inhibited carbon steel or lined pipe. For most material selection and qualification programs for sour applications the material is tested in accordance with NACE MR0175 / ISO 15156 at the maximum design temperature and at ambient temperature (i.e. 24 ±3°C). However WMSS may be more susceptible to Sulfide Stress Cracking (SSC) below ambient temperature and current information in the literature is limited. Consequently qualification to the requirements of NACE MR0175 / ISO 15156 may show acceptable results, whereas in-service cracking could result due to exposure to temperatures below ambient. This may not be applicable for some applications, however for sub-sea pipelines the typical seabed temperature is in the region of 5°C, which may be experienced during `shut-in' conditions. SSC testing has been undertaken on WMSS at ambient and seabed temperatures using four-point bend (FPB) specimens in simulated condensed water (CW) and produced water (PW) environments at two partial pressures of H2S for parent line-pipe in the as-received and fully-machined conditions. In addition a test method has been developed to closely control the test parameters, with particular regard to dissolved oxygen and pH in order to ensure consistency of results.
- Europe > Norway > Norwegian Sea > Halten Terrace > Block 6507/11 > Åsgard Field > Åre Formation (0.99)
- Europe > Norway > Norwegian Sea > Halten Terrace > Block 6507/11 > Åsgard Field > Tofte Formation (0.99)
- Europe > Norway > Norwegian Sea > Halten Terrace > Block 6507/11 > Åsgard Field > Tilje Formation (0.99)
- (39 more...)
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (1.00)
ABSTRACT Recent examples of improperly heat-treated duplex fittings have created the need for rapid test methods for identification of sigma phase and other intermetallic phases. Several attempts have been made to simplify known methods in order to make them applicable for on-site testing. Yet metallographic examination is the only known technique that is reliable. It is sometimes combined with ferrite measurement for pre-screening. The possibilities of applying electrochemical techniques have been evaluated on duplex specimens representing different levels of sigma phase. The applied test methods include ASTM G150 for Critical Pitting Temperature (CPT) determination as well as simpler approaches for measuring the resistance against localized corrosion quickly. The preliminary results of the ongoing study are promising. Distinguishing between sensitized and non-sensitized duplex steel was obtained within few minutes by performing a potentiostatic test that may be suitable for on-site testing.
- Europe (0.47)
- North America > United States > Texas > Harris County > Houston (0.16)
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (1.00)
ABSTRACT The presence of severe corrosive environment along with higher external pressure in the Black sea has led to develop high strength heavy wall offshore sour service linepipe. The paper will cover the successful development of high strength API 5L X70 Sour Service, Fracture arrest properties, Dimensions, High Utilization (SFDU) (33 inch OD x 39.5 mm WT) linepipe manufactured by the J-C-O-E technology. Pipe rolling and welding parameters were controlled to minimize the circumferential residual stress and weld and Heat Affected Zone (HAZ) hardness in order to enhance the Hydrogen Induced Cracking (HIC) / Sulphide Stress Corrosion (SSC) resistance. The proper selection of wire and flux has resulted in average Charpy V-Notch (CVN) energy >100 J at -30°C in the weld centerline. The study of weld microstructure showed the co-relation of weld ductility (measured in all-weld specimens) with grain boundary ferrite. The hardness of the weld centerline was <225 HV 10 kgf even with overmatching of weld tensile strength. Plate selection with respect to alloy design and microstructure was critical to obtaining good HIC and SSC resistance for heavy wall linepipe. The levels of S<0.0010% and P<0.008% along with low value of Nb+V+Ti <0.055%, Parameter crack measurement (Pcm)<0.15% and Carbon Equivalent (CE)<0.38% were obtained in the plates.
- Research Report > New Finding (0.68)
- Research Report > Experimental Study (0.54)
- Geology > Mineral (0.88)
- Geology > Geological Subdiscipline > Geomechanics (0.70)
ABSTRACT Over the last decade, significant advances in chemical inhibition have enabled operators to use carbon steel pipework in oil and gas facilities where sand production is a concern. The ability of these chemicals to reduce both the electrochemical corrosion reactions and the mechanical damage attributed to particle impingement is well documented but the underlying mechanisms have been the subject of less attention. This paper presents a review of three commercially available oilfield corrosion inhibitors (two standard corrosion inhibitors and one high shear resistant inhibitor) in an effort to establish their performance in erosion-corrosion environments. Experiments were conducted at 45°C using a submerged impinging jet (SW) in CO2-saturated conditions with a fluid velocity of 14 m/s and sand loading of 500 mg/L. A combination of gravimetric measurements, in-situ electrochemistry and surface profilometry allowed the inhibitors to be assessed based on a number of different parameters (i.e. reduction in weight loss, in-situ corrosion rate behavior and total penetration depth). The results demonstrated the importance of surface analysis techniques when evaluating the performance of chemicals, indicating that weight loss and in-situ electrochemical techniques alone can sometimes provide misleading information on inhibitor performance in laboratory tests. This evaluation is conducted in erosion-corrosion environments where no semi-protective corrosion product formation occurs. AC impedance measurements have also been incorporated into the analysis to assist in interpreting inhibition mechanisms and determine how chemicals can reduce both the erosion and corrosion components of damage.
ABSTRACT The present study describes the impact of mineral deposits (SiO2, Al2O3 and CaCO3) on CO2 corrosion of 1030 carbon steel in a chloride-containing environment. The corrosion process was investigated using electrochemical and weight loss measurements, followed by surface analysis of the corroded steels conducted by visible-light and scanning electron microscopy. It was found that the extent of the corrosion damage is directly related to the nature of the mineral deposits and significant differences were observed in the morphology of the surfaces corroded in the presence/absence of different deposits. The susceptibility of the deposit-covered steels to localized corrosion and the influence of deposits on corrosion inhibition are also discussed and related to the properties of the deposits. The inhibitor performance at deposit-covered steels varied according to the chemical composition of the inhibitor and the nature of the deposit. The study serves to improve the understanding of CO2 corrosion process in the presence of solid deposits and the findings can be applied to address the under-deposit corrosion in oilfield operations.
- Europe (0.46)
- North America > United States > Texas > Harris County > Houston (0.16)
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (1.00)
ABSTRACT This paper seeks to increase the understanding of under-deposit corrosion with sand and the development of better inhibitors to mitigate this type of corrosion under sweet (carbon dioxide) conditions. In these tests an electrode exposed to the bulk solution and an electrode under the sand were galvanically coupled. This method represents the under-deposit corrosion condition within oil and gas pipelines, mimicking how the pipe surface can be covered by solids such as sand. The corrosion rates of both electrodes were monitored simultaneously using the linear polarization resistance technique. Zero resistance ammetry was used to measure the coupling current between the electrodes underneath the sand and in the bulk solution. After injection of inhibitors, the under-deposit electrode acted as the local anode and a dramatic acceleration of its corrosion was observed. The linear polarization resistance corrosion rate, the potential of the coupled electrodes, and the galvanic current density before and after the injection of inhibitors were used to characterize the corrosion inhibitor performance. Factors that affect the under-deposit corrosion measurement, such as the sand thickness, inhibitor concentration and temperature, were investigated and utilized in order to assist in the future development of higher performing corrosion inhibitors for this environment.
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (1.00)