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Collaborating Authors
Results
The Laboratory Evaluation of Seawater Injection on H2S Production, Incorporating Several Different Treatment Strategies, Utilizing Fixed Film Upflow Bioreactors
Hoffmann, Heike (Intertek Production & Integrity Assurance) | Harris, Kevin (Intertek Production & Integrity Assurance) | Palmer, Jim (Intertek Production & Integrity Assurance)
ABSTRACT Reservoir Souring is the unplanned production of increased concentrations of hydrogen sulfide (H2S) in wellstream fluids from production wells that are subjected to water-injection. The consequences of souring with respect to safety, corrosion and environmental risk can be significant. This is typically associated with the activity of a specialized group, the Sulfate-reducing bacteria (). However, in recent years, various other micro-organisms are believed to be involved in souring, e.g. Sulfate reducing archaea (). In this study, fixed film up flow bioreactors () were utilized to assess the potential for H2S production or changes in such H2S production, when seawater is injected into a North Sea oil reservoir. The study has demonstrated how changes in fundamental parameters (e.g. bacterial nutrients, shut-in periods) can impact sulfide production and alter the microbial communities. The were soured to create a ‘worst case’ scenario and different nutrient additions or remediation treatments were applied to represent either near injection wellbore or deep field conditions. Typical oil field practice is to measure H2S in the gas phase. Partition modelling of H2S between water, oil and gas phase was applied to the measured sulfide data to give a real-world indication of the effect of H2S in gas when resuming production following a shut-in. The following parameters were measured during the testing period: sulfide generation, volatile fatty acid organic carbon sources (), iron, nitrate and nitrite concentrations. The microbiology of the system was evaluated both by traditional culture techniques and molecular methods, such as fluorescence in situ hybridization (FISH) analysis and other -based analysis. Results indicate that when sulfide generation had reached 1.5 mM, and the nutrient source was changed, almost complete cessation of sulfide generation resulted for a period of 7 days. Whereas, following shut-in period, sulfide generation recommenced after re-starting the flow and reached a concentration of 4.4 mM immediately and rose even higher to 5.0 mM over the first days of flow. However, sulfide concentrations returned to 2.0 mM again within 7 days after restart. However, the changes in the microbial community were found to be somewhat selective to certain SRB families. The various effects of the different treatments and conditional changes are discussed further in this paper.
- Europe > United Kingdom (0.89)
- North America > Canada > Alberta > Woodlands County (0.24)
- North America > United States > Texas > Harris County > Houston (0.16)
- Materials > Chemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Constituents > Bacteria (0.35)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.34)
A Mechanistic Erosion-Corrosion Model for Predicting Iron Carbonate (FeCO3) Scale Thickness in a CO2 Environment with Sand
Al-Aithan, G.H. (Saudi Aramco) | Al-Mutahar, F.M. (Saudi Aramco) | Shadley, J.R. (The University of Tulsa) | Shirazi, S.A. (The University of Tulsa) | Rybicki, E.F. (The University of Tulsa) | Roberts, K.P. (The University of Tulsa)
ABSTRACT CO2 (sweet) corrosion is one of the most dominant mechanisms of destruction of carbon steel equipment and piping used by the oil and gas industry. The presence of sand can accelerate the damage significantly. The combined effect of sand erosion and CO2 corrosion on carbon steel tubing and piping can greatly influence material selection for the design and affect operation of oil and gas production facilities. However, for some operational and environmental conditions, FeCO3 scale that is formed as a result of CO2 corrosion can provide some protection against the erosion-corrosion environment. Many investigators have conducted research to investigate the conditions for which iron carbonate scale forms and provides protection, but only a few have examined erosivity of FeCO3 scale. The erosion resistance of FeCO3 scale to solid particle erosion (erosivity) has been characterized in the current work under various environmental conditions in submerged, direct impingement flow loop experiments. A mechanistic model has been developed that includes the competition between the growth of FeCO3 scale through CO2 corrosion and the removal of scale by sand erosion. The model then predicts the corrosion rate for scale-forming conditions, when sand is produced. The effects of sand concentration, solution chemistry, temperature, and flow velocities on erosion-corrosion rates have been examined. A computer program has been developed, based on the mechanistic model, to predict erosion-corrosion rates.
- Asia > Middle East > Saudi Arabia (0.46)
- North America > United States > Texas > Harris County > Houston (0.17)
ABSTRACT Seawater injection into oil reservoirs for secondary oil recovery is frequently accompanied by souring (increased sulfide concentrations). Production of hydrogen sulfide causes various problems, such as microbiologically influenced corrosion (), deterioration of crude oil. Sulfate-reducing bacteria () are considered to be major players in souring. Volatile fatty acids (s) in oil field water are assumed to be produced by microbial degradation of crude oil. The objective of this research is to investigate mechanisms of souring from the view of production by the crude oil biodegradation. A microbial consortium collected from oil-water separator was suspended to seawater. Crude oil or liquid n-alkane mixture was added to the culture medium as sole carbon source. Anaerobic incubation was conducted for 190 days. Physicochemical analysis showed that preferable toluene degradation and sulfate reduction occurred concomitantly in crude oil amended condition. Sulfide concentration was much lower in alkane mixture amended condition than that of crude oil amended condition. These observations suggest that are related to toluene activation and consumption steps in crude oil degradation. Therefore, the electron donors for were not only , but a lot of crude oil components, especially toluene. Alkanes were also degraded by microorganisms, but did not so contribute to reservoir souring.
- Asia > Japan (0.95)
- North America > United States > Texas (0.19)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
NSOD, A&OI Anchorage, AK ABSTRACT Corrosion inhibition to mitigate preferential weld corrosion (PWC) was studied experimentally using the metallurgical condition of the welds and the inhibitor concentration as independent variables. The study used Tafel polarization and electrochemical noise tests on multi electrode assemblies fabricated from sections of parent metal, heat affected zone (HAZ) and weld metal. This technique allows testing of each component separately as well as quantifying galvanic coupling effects. In welds susceptible to PWC, adequate corrosion inhibitor concentration is effective in reducing galvanic corrosion, due to the shifts in the relative corrosion potentials. However the effect depends on the inhibitor dosage. Under dosage actually increases the corrosion rate and exacerbates the effect of the galvanic coupling. INTRODUCTION The seawater injection system is a critical component of the pipeline network that supplies and sustains a significant part of the oil production in mature oilfields fields. Inspections in these pipelines reveal significant damage associated with fabrication welds in the pipeline.
- Research Report > New Finding (0.46)
- Research Report > Experimental Study (0.46)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.40)
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (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 Within the project COORAL (German acronym for "CO2 purity for capture and storage") studies on piping steels exposed to circulating supercritical impure carbon dioxide (CO2) have been carried out. In order to simulate the real conditions in pipelines, impurities such as carbon monoxide (CO) – 750 ppm(v), sulfur dioxide (SO2) – 70 ppm(v), nitrogen dioxide (NO2) – 100 ppm(v) and oxygen (O2) – 8100 ppm(v) were added to the CO2 stream before compression. Water content was varied from 1000 ppm(V) down to 500 ppm(V). Exposure experiments were carried out using steel specimens placed in the autoclaves. CrMo, C- and 13Cr-steels have been exposed to circulating supercritical impure CO2 for up to 186 days at 333 K and 10 MPa. Surface analysis and weight loss experiments in order to determine the corrosion products and the corrosion rates have been carried out, respectively. General uniform corrosion has been observed on carbon steel and CrMo-steel. However, corrosion rates are very low and are strongly dependent on water content in CO2 streams. It has been shown that 13Cr-steel is susceptible to pitting corrosion in the investigated environments at high water contents.
- Europe > Germany (0.28)
- North America > United States > Texas (0.15)
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Reservoir Description and Dynamics (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 Brackish water (BW) is used to supplement boiler feed water in processes. In Alberta, water quality from the McMurray (McM) and Grand Rapids () formations typically consists of approximately 1% salinity, 750 ppm bicarbonate and 15 ppm H2S. The carbon steel () piping originally used in this service experienced severe corrosion and failures after only five years of service. General corrosion rates () based on corrosion coupons were as high as 8 mm/year (320 mpy). Many of the failures occurred on elbows, tees and reducers. A detailed analysis of the overall process and chemistry identified unique corrosion mechanisms that existed in certain process stages. Depending upon the needs of the process, the corrosion could in fact be mitigated by controlling specific process parameters. Failure analysis showed siderite to be the main corrosion product. A novel mechanism of CO2 corrosion with impingement was proposed and manifested. In rotating cylinder electrode () tests, bicarbonate/CO2 corrosion rates accelerated from 0.125 to 1.75 mm/year (5 to 70 mpy) by increasing the cylinder rotating speed from 2,000 to 5,000 rpm. These results supported the theory that CO2 cavitation significantly aggravated corrosion. As a result, a caustic injection program was implemented in the field to control pH to 9.0 to suppress the CO2 release from the aqueous phase. Subsequent corrosion coupon data indicates a dramatic drop in corrosion rates to a range of 0.025 to 0.125 mm/year (1 to 5 mpy). In piping stages where pH control wasn’t possible for process reasons, the piping was replaced with duplex piping materials.
- North America > Canada > Alberta (0.49)
- North America > United States > Texas > Harris County > Houston (0.16)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Sourcing (0.63)
ABSTRACT Breakdown causes of copper/copper sulphate (Cu/CuSO4) permanent reference electrodes placed in soil have been analyzed and durability ways were revealed. Breakdown of copper/copper sulphate (Cu/CuSO4) permanent reference electrodes occurs because of internal electrolyte’s copper ions lack; primordial shortage of copper sulphate crystals; bonding of copper ions into an insoluble deposition; a large area of membrane. Wrong values of coupon potentials can be conditioned by coppering process of the coupons and potential shift to positive direction by this reason. Copper/copper sulphate (Cu/CuSO4) permanent reference electrodes’ service life increase ways have been offered. Problems which appear by an application of copper/copper sulphate permanent reference electrodes could be avoid if using of silver/silver chloride reference electrodes which deprived the most above-listed disadvantages. Using of silver/silver chloride reference electrodes in soils and the "100 mV shift" protection criterion are offered for discussion.
- Europe (0.46)
- North America > United States > Texas (0.20)
ABSTRACT The recommended practice for the microbiological analysis of samples from oilfield sources is to analyze the samples as rapidly as possible and if inoculation of microbial growth media in the field is not possible it is recommended that samples should be kept on ice during transport and to complete processing of samples within 24 hours. It is not always possible to process microbiological samples within 24 hours but data is lacking that quantifies the amount of microbial community changes occurring in oilfield samples that have been stored with and without refrigeration for 24 hours or more. In this study, oilfield samples of predominantly Sulfate Reducing Bacteria (), Acid Producing Bacteria (), and General Heterotrophic Bacteria () were subjected to four storage conditions: refrigeration (4°C), room temperature (25°C), 35°C, and daily cycling between 25°C and 35°C. The microbial populations in these samples were monitored over a 7 day period using microbiological growth media. Refrigeration at 4°C preserved the sample fairly well, but decreased microbial concentrations were observed after 7 days. Samples stored at 25°, 35°, or cycled from 25° to 35°C showed increased bacterial concentrations under all conditions.
ABSTRACT Current testing standards provide details on how to determine Critical Stress Intensity Factor (KISSC) of C110 material (microalloyed AISI 4130 steel – UNS G41300) in 100% and 7% H2S. At 100% H2S, American Petroleum Institute (API) and National Association of Corrosion Engineers International (NACE) require a non-buffered Solution A for testing. For testing in 7% H2S, the test solution is buffered at pH 4.0 and N2 is the carrier gas. The European Federation of Corrosion Publication 16 (EFC) recommends a different test environment, in which the test solution is buffered to pH 4.5 for all H2S concentrations and the carrier gas is CO2 for testing in milder H2S environments. The recommended crack starter choices also vary. These test variables affect the final KISSC values. This paper presents Critical Stress Intensity Factor (KISSC) data generated for two heats of standard mill produced C110 casing steel under varying applied loads and in three H2S environments - (i) NACE Solution A with no pH control using N2 as the carrier gas, (ii) NACE Solution A with no pH control with CO2 as the carrier gas, and (iii) buffered EFC solution with pH controlled at 4.5 using CO2 as the carrier gas. Double cantilever beam (DCB) samples from both materials were tested in A and solutions to the requirements of NACE Standard TM0177 Method D in various sour environments under a range of applied loads. The KISSC and KILIMIT data generated under three environments are compared. A relationship between KISSC - KILIMIT and KILIMIT - H2S is trended.
- Research Report > New Finding (0.68)
- Research Report > Experimental Study (0.47)
ABSTRACT Maintaining pipeline integrity is crucial in the oil & gas industry, and when pipeline defects are detected, or pipeline failures occur, understanding the cause of these events is of utmost importance. Corrosion can have multiple causes and one of these is microbiologically influenced corrosion or . Accurate detection and quantification of corrosion associated microorganisms requires that samples should be obtained and analyzed as quickly as possible when microbial growth tests are used. However, is not always considered when beginning an investigation of a pipe segment that is removed from service. It is not uncommon to have a pipe segment removed from service and sitting in a warehouse for days or even months before the possible involvement of is considered. In this event microbial growth tests can’t be used, but genetic testing can be employed to detect and quantify bacteria, particularly if under-deposit corrosion and/or deep pits are present. Data are presented for several case histories of the use of both microbial growth testing and genetic testing (quantitative polymerase chain reaction or qPCR) to examine the microbial population in fresh and not-so-fresh samples of corroded pipe.
- Health & Medicine > Pharmaceuticals & Biotechnology (1.00)
- Energy > Oil & Gas > Upstream (0.95)
- Energy > Oil & Gas > Midstream (0.69)