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Results
The Effect of Buffering Capacity on HIC Behavior for FFP Evaluation
Mizuno, Daisuke (JFE Steel Corporation) | Ishikawa, Nobuyuki (JFE Steel Corporation) | Kobayashi, Kenji (Nippon Steel & Sumitomo Metal Corporation) | Hara, Takuya (Nippon Steel & Sumitomo Metal Corporation) | Tada, Eiji (Nippon Steel & Sumitomo Metal Corporation)
ABSTRACT Hydrogen Induced Cracking (HIC) is a major issue of line pipe steels exposed to sour environments. In general, 5.0 wt% NaCl and 0.5 wt% CH3COOH solution with 0.1 MPa H2S specified as solution A in NACE TM0284 is used to evaluate the resistance of steel plates and pipe products. However, in many cases, the test condition is too severe compared to the actual field conditions. Therefore, Fit-For-Purpose () evaluation method has been the subject of considerable investigations in recent years. The Iron and Steel Institute of Japan (ISIJ)(1) high-strength line pipe () Research Committee proposed the buffer solution which contained high concentration of acetic acid and sodium acetate for test including mildly sour conditions. In a previous study, it was shown that the newly proposed test solution had a strong pH buffering capacity in the range of pH 3.5 to 5.5 under 0.1 MPa H2S. In this paper, the influence of pH buffering capacity of the solution on behavior was investigated and crack area ratio was strongly affected by pH shift during test. In addition, pH buffering capacity of the solution under lower H2S partial pressure was evaluated for evaluations. The test solution which contained high concentration of acetic acid and sodium acetate showed an excellent pH buffering capacity compared with the conventional test solution.
- Asia > Japan (0.49)
- North America > Canada > Alberta (0.28)
- North America > United States > Texas > Harris County > Houston (0.17)
ABSTRACT Phosphonate scale inhibitors (SIs) applied in downhole squeeze applications may be retained in the near-well formation through adsorption and/or precipitation mechanisms. In this paper, we focus on the properties of precipitated "mixed" calcium and magnesium phosphonate complexes formed by nine common phosphonate species. By "mixed", we mean anionic SI bound to both calcium and magnesium divalent cations, i.e. the complex SI_Can1_Mgn2 is formed where n1 and n2 are the stoichiometric coefficients for Ca and Mg, respectively. The stoichiometry (n1 and n2 or the Ca/P and Mg/P molar ratios) in various precipitates is established experimentally and the effect of solution pH on the molar ratios of Ca/P and Mg/P in the precipitate is determined. Static precipitation tests were carried out varying the amounts of Ca and Mg present in the system at test temperatures ranging from 20°C to 95°:C, at a fixed [SI] = 2,000ppm. The solution molar ratio of Mg/Ca was varied but the ionic strength of each test solution was kept constant. In addition, tests were also carried out with (i) only Ca and SI present, and (ii) only Mg2+ and SI present. The molar ratios of Ca2+/P and Mg2+/P in the solid precipitates were determined by assaying for Ca2+, Mg2+ and P in the supernatant liquid under each test condition by ICP spectroscopy (Cao, Mgo and Po are known, but they are also measured experimentally). We show experimentally that the molar ratios of precipitated Ca/P and Mg/P (or Ca/SI and Mg/SI) depends on the nature of the SI (i.e. how many M2+ binding sites there are per molecule); solution pH; the relative magnitude of the SI binding constants to Ca and Mg at the test pH; and the solution molar ratio of Mg2+/Ca2+; for all phosphonates tested. It is found that, as pH increases, the combined molar ratio of Ca/P+Mg/P, i.e. n1+n2 in the SI_Can1_Mgn2 complex increases up to a theoretical maximum, depending on the chemical structure of the phosphonate. Our findings are consistent with proposed phosphonate SI-Ca-complex structures which were presented and discussed in two SPE technical papers (SPE 155114, 2012 and SPE 164051, 2013).
- Asia > Middle East (0.28)
- North America > United States > Texas > Harris County > Houston (0.17)
- Materials > Chemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Constituents > Salts/Sulphates/Scales (0.72)
Minimizing Grounding Resistance of Cathodic Protection Anode Bed with Finite Element Method
Wuxi, Bi (PetroChina Pipeline R&D Center) | Chengwei, Xu (PetroChina Pipeline R&D Center) | Zhiyuan, Xue (PetroChina Pipeline R&D Center) | Hongyuan, Chen (PetroChina Pipeline R&D Center) | lingli, Liu (PetroChina Pipeline R&D Center)
Cathodic protection (CP) anode bed grounding resistance calculating formulae, given by CP standards, are reviewed firstly. Underground assumptions and limitations of these grounding calculating formulae are analyzed, which means formula method may encounter problems when designing anode beds in high soil resistivity area. Based on finite element analysis (FEA) method, a new grounding resistance calculation method is suggested, which is can be treated as more suitable and flexible for anode bed grounding resistance calculation in high soil resistivity condition. The main steps of FEA method, geometric model building, meshing, boundary condition and solver setting, and grounding resistance calculating according to Ohmic law, are clearly presented. In order to introduce the FEA method in detail, a realistic anode bed design program for Northwestern China area, where soil resistivity is always very high, is demonstrated. Based field soil resistivity survey data by Wenner 4‐pin method, the candidate anode bed site, named Station A, is regarded as optimal site, and Barnes' soil layer analysis method is used to predict soil resistivity distribution in depth direction. Both formula method and FEA method are used to calculate grounding resistance. The following comparison results show that formulae from COR‐GS‐023, GB21448‐2008, РД 153‐39.4‐039‐99
- Asia > China (0.68)
- Asia > Russia (0.47)
- North America > United States > Texas (0.18)
- Energy > Oil & Gas (1.00)
- Government > Regional Government > Asia Government (0.68)
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)
ABSTRACT For a given production system, the corrosion mitigation philosophy is usually established based on the fluid properties and the operating parameters pre-identified within the Basis of Design (BOD). Information in the BOD comes from reservoir simulation, process/flow modeling, and thermodynamic/ compositional fluid analyses. These data have limited accuracy and a wide variability throughout the field life. Very often and due to capital expenditure (CapEx) constraints, most of production facilities primarily utilize carbon steel lines with corrosion mitigation provided by injection of chemical inhibitors. When using carbon steel and inhibition, a successful operation requires active corrosion monitoring to keep tabs on effectiveness of the chemical inhibition program. The monitoring program is a key to proactively identify new corrosion mechanisms surfacing during the field operation. Due to the wide variety of operating conditions, it is not practical to run laboratory corrosion tests simulating every production scenario. Most of the corrosion predictions rely heavily on the laboratory test results; however, the tests have limitations and may not precisely cover all of the corrosion mechanisms in predicting field performance. Depending on new mechanisms identified by the corrosion monitoring program, corrective actions are usually taken. These actions may include additional chemical treatments and mechanical systems such as pigging to bring the corrosion under control. This paper discusses some of the interesting corrosion mechanisms that have emerged in production systems due to changes in operating conditions during field operations. Corrosion monitoring data with fluid analyses, flow modeling, and additional laboratory testing have been effectively used to understand the corrosion mechanism and develop solutions for control. This work focuses on internal corrosion control of carbon steel in production and transportation lines with single or multiphase flow.
- 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)
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 As part of continued efforts by an operating company to address specific corrosion mitigation needs and utilize improved integrity chemicals such as corrosion inhibitor, scale inhibitor, oxygen scavenger, biocides as well as operational chemicals such as antifoam, coagulants, anionic and cationic polyelectrolytes etc. offered by different chemical suppliers, it is necessary to conduct field trials at the existing facilities. Such chemical field trials pose specific challenges to the extent of causing even un-planned shutdown of the facilities. This paper outlines some of the typical problems encountered by facility operators and corrosion monitoring personnel right from shortlisting of chemical vendors, performing compatibility tests, establishing evaluation criteria, until the issue of the field trial report to the asset owners. Issues highlighted in this paper are based on field trials conducted at the Kuwait Oil Company () for their Seawater Treatment Plant () supplying treated seawater to the Central Injection Plant Facility (). Products supplied by three different chemical suppliers were utilized in the trials and unique challenges were faced in each case.
- Water & Waste Management > Water Management (1.00)
- Materials > Chemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > Sabriyah Field > Marrat Formation > Upper Marrat Formation (0.94)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > Sabriyah Field > Marrat Formation > Sargelu Formation (0.94)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > Sabriyah Field > Marrat Formation > Sabiriyah Mauddud (SAMA) Formation (0.94)
- (4 more...)
- 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)
- (2 more...)
The Importance of Internal Corrosion Monitoring In Seawater Treatment and Injection Plants for Integrity Management
Jarragh, Amer (Kuwait Oil Company) | Srinivasan, Balasundaram (Kuwait Oil Company) | Al-Sulaiman, Saleh (Kuwait Oil Company) | Khuraibut, Yousef (Kuwait Oil Company) | Islam, Moavin (Corrpro Companies, Inc.)
ABSTRACT Internal corrosion monitoring in operating facilities can be conducted with online monitoring equipment that include Corrosion Coupons, Corrosion Probes, Bio probes, etc. installed at key locations within the facility. In conjunction with corrosion monitoring, fluid analyses activities can also be carried out for different processes to determine various key parameters such as pH, conductivity, TDS, Total Hardness, Dissolved Oxygen content, scaling elements concentrations, Corrosion and Scale Inhibitor residuals, Fe content (total and dissolved), bacterial activity etc. Corrosion data and fluid characteristics can then be analyzed for trends and appropriate recommendations issued to asset owners for corrective and/or preventive measures to mitigate corrosion and also to advise Inspection requirements. This paper highlights two facilities at a Middle Eastern oil production company, the Sea Water Treatment Plant (SWTP) and Central Injection Pump Facility (CIPF), where internal corrosion monitoring and fluid analyses are carried out on a routine basis. Results from these activities have been utilized to compare with actual findings during facility shutdown to evaluate the monitoring / mitigation efforts which have contributed to the integrity of the plants.
- Asia > Middle East > Kuwait (0.31)
- North America > United States > Texas (0.19)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Treatment (0.68)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > Sabriyah Field > Marrat Formation > Upper Marrat Formation (0.94)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > Sabriyah Field > Marrat Formation > Sargelu Formation (0.94)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > Sabriyah Field > Marrat Formation > Sabiriyah Mauddud (SAMA) Formation (0.94)
- (4 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 Many pipelines used to transport high pressure gas to long distances are made from carbon steel plates by spiral welding. There are instances in which such pipelines gave a long service in sour atmospheres. But, when they failed, they failed catastrophically and sometimes repeated failures occurred. In one such failure instance, the pipeline in the subject case gave a service life of about 12 years in sour gas service. In year 2012, the pipeline failed suddenly by cracking along the heat affected zone (H.A.Z.) of the spiral weld. Onwards, frequent failures began to occur in identical fashion at different locations. This prompted for a failure investigation to be carried out. Mechanical, metallurgical and chemical tests and analyses have been carried out to understand the natures of the failures. The paper presents the findings and a discussion on the correlation of mechanical, metallurgical and chemistry parameters to the type of failure that has occurred.
- North America > United States > Texas (0.21)
- Asia > Middle East > Kuwait (0.17)
- Materials > Metals & Mining (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- 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)
The areas of the oil field reserves are spread all over the country. For the sake of convenience and proper management of these oil fields reserves have been divided into four areas - North, South, East and West. In each of these areas oil producing wells, crude gathering centers for processing the raw crude, gas booster stations for processing and enhancing the pressure of the gas to enable transportation of gas, and water treatment/injection plants have been constructed. The pipelines, which are interconnecting various facilities across the four areas are buried cross country lines, transport different process treated fluids -dry crude, dry high pressure (HP) gas, low pressure (LP), fuel gas, condensate and treated water. Hence the challenge for corrosion monitoring is all the more complex. It is worthy of notice that the task of the Internal Corrosion Management Plan becomes more challenging due to the changes in the fluids' characteristics, the expansion of the pipeline network, and the location; especially that mostly of the pipelines are cross country and sometimes in remote or residential areas. The present paper focuses on the Internal Corrosion Management Plan of two of high pressure (HP) gas pipelines with company's tag numbers HP042 and HP057, different diameters, lengths and constructed from API
- North America > United States > Montana > Sheridan County (0.45)
- North America > United States > Texas > Harris County > Houston (0.18)
- 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)