Microbiologically Influenced Corrosion Combined with Under-Deposit Corrosion Mechanism and Control Technology in Water Injection Wells of Middle East Carbonate Oilfield

2021 ◽  
Author(s):  
Zhengrong Ye ◽  
Huachang Chi ◽  
Xiang Zhou ◽  
Zhiwen Yang ◽  
Weidong Jiang ◽  
...  
Keyword(s):  
Middle East ◽  
Corrosion Rate ◽  
High Salinity ◽  
Water Injection ◽  
Corrosion Products ◽  
Microbiologically Influenced Corrosion ◽  
Corrosion Mechanism ◽  
Corrosion Prevention ◽  
High Hydrogen ◽  
Corrosion Failure

Abstract A carbonate oilfield in the Middle East carries out the mixed water injection of produced water and fresh water, after 1 year of its rapid exploration. The injected water is highly corrosive, with high salinity, high chloride concentration and high hydrogen sulfide. Recently, there are dozens of corrosion perforations on L80 tubing in injectors within 2 years in the field and the corrosion rate reaches 3.6 mm/a. After the tubing leaks, the injected water enters into the annulus between the tubing and casing, which causes casing corrosion, damages the well integrity, and greatly influences the field production. In this paper, the causes for such rapid tubing corrosion failure are investigated by using optical metallographic microscopy, scanning electron microscopy (SEM), energy dispersive spectrometer (EDS) X-ray diffraction (XRD), and combined with the weight loss and bacteria testing. Firstly, test the element composition of the L80 tubing to verify the tubing quality. Secondly, conduct the corrosion experiments of H2S and dissolved oxygen. Thirdly, analyze the morphology and corrosion product composition of failure tubing. The results indicate that the failed L80 tubing material meets the requirements of API SPEC 5CT-2011 standard. The localized corrosion rate of L80 is 0.293~0.697 mm/a at whole well depth in the simulated injection water. Bacteria were detected in both the injected water and the corrosion products of the failed tubing. In addition, the corrosion products of failed tubing are mainly FeS, CaCO3 and Fe3O4, which indicates that the synergistic effect of microbiologically influenced corrosion and under-deposited corrosion promote the perforation of tubing. Then the corrosion prevention strategy of UHMWPE lined tubing was proposed. UHMWPE lined tubing has been applied in nine water injectors. After one year and a half, one of the water injector’s UHMWPE lined tubing has been detected, no corrosion perforations observed, and the scale deposition became slightly. This case provides useful practical experience for corrosion prevention of high salinity and high acid injection well in carbonate oilfields.

Effect of Temperature and H2S Concentration on Corrosion of X52 Pipeline Steel in Acidic Solutions

2013 ◽  
Vol 743-744 ◽  
pp. 589-596 ◽  
Author(s):  
Meng Liu ◽  
Jian Qiu Wang ◽  
Wei Ke
Keyword(s):  
Corrosion Rate ◽  
Pipeline Steel ◽  
Corrosion Products ◽  
Effect Of Temperature ◽  
Corrosion Mechanism ◽  
General Corrosion ◽  
Ferrous Sulfide ◽  
Immersion Corrosion ◽  
Different Temperatures ◽  
Diffraction Patterns

The corrosion behavior of X52 pipeline steel in H2S solutions was investigated through immersion corrosion test which was carried out in a high temperature and high pressure autoclave at different temperatures and H2S concentrations. General corrosion rates were calculated based on the weight loss of samples. The morphology and the chemical composition of the corrosion products were obtained by Scanning Electron Microscopy (SEM) and Energy Dispersive Spectroscopy (EDS). The crystal structure of corrosion products was analyzed by X-Ray diffraction patterns (XRD). The corrosion products consisted mainly of the sulfide compounds (mackinawite, cubic ferrous sulfide, troilite and pyrrhotite). The corrosion products included two layers: the inner iron-rich layer and the outer sulfur-rich layer. Under H2S concentrations of 27g/L, the corrosion rate increased with the increase of temperature up to 90°C and then decreased at 120°C, finaly increased again. The corrosion rate first increased with H2S concentrations then decreased at 120°C. The structure and stability of the corrosion products due to different corrosion mechanism had a major impact on the corrosion rate. The corrosion resistance of the corrosion products increased as follows: mackinawite < cubic ferrous sulfide < troilite < pyrrhotite.

scholarly journals Corrosion Failure Mechanism of Associated Gas Transmission Pipeline

Materials ◽  
2018 ◽  
Vol 11 (10) ◽  
pp. 1935 ◽  
Author(s):  
Weimin Zhao ◽  
Timing Zhang ◽  
Yonglin Wang ◽  
Jianhua Qiao ◽  
Zerui Wang
Keyword(s):  
Corrosion Rate ◽  
Gas Pipeline ◽  
Corrosion Products ◽  
Oxygen Absorption ◽  
Co2 Corrosion ◽  
Uniform Corrosion ◽  
X Ray Diffraction ◽  
Corrosion Failure ◽  
Associated Gas ◽  
Transmission Pipeline

Corrosion has been responsible for several gas pipeline leakage accidents; thus, clarifying its failure mechanisms is a precondition to prevent such accidents. On the basis of failure analysis of corroded pipe sections, laboratory exposure tests were conducted by simulating three possible corrosion environments inside a gas pipeline. The corrosion rate indicated by depth change was adopted in this study. Scanning electron microscopy and X-ray diffraction were used to analyze corrosion products. Results showed that the specimens completely immersed in condensate water were generally corroded and that the specimens exposed to gas were locally corroded. However, the corrosion rate of the latter was slightly lower; hence, no autocatalysis of occluded corrosion cell occurred in the formation of corrosion pit, and uniform corrosion occurred in the precipitation location of condensate water. The areas in the range of 5 mm below the waterline indicated severe corrosion, and the rate could reach twice that of other areas. The corrosion products were mainly FeO(OH) and FeCO3, thereby proving that the corrosion failure of pipelines was caused by oxygen absorption corrosion and CO2 corrosion. Suggestions were presented to control corrosion failure of associated gas pipelines.

An Overview of Cu Wire Intermetallic Compound Formation and a Corrosion Failure Mechanism

2012 ◽  
Author(s):  
Dongmei Meng ◽  
Laura Buck ◽  
James Cargo
Keyword(s):  
Electron Microscopy ◽  
Transmission Electron Microscopy ◽  
Corrosion Mechanism ◽  
Fundamental Study ◽  
Corrosion Failure ◽  
Transmission Electron ◽  
Intermetallic Compound Formation ◽  
Scanning Transmission ◽  
Low K

Abstract Cu needs a higher level of ultrasound combined with bonding force to be bonded to the Al pad properly, not just because Cu is harder than Au, but it is also harder to initiate intermetallic compounds (IMC) formation during bonding. This increases the chances of damaging the metal/low k stack under the bondpad. This paper presents a fundamental study of IMC as well as one example of a failure mode of Cu/Al bonded devices, all based on detailed analysis using scanning electron microscopy, scanning transmission electron microscopy, energy dispersive spectrometers, and transmission electron microscopy. It presents a case study showing a corrosion mechanism of Cu/Al ballbond after 168hr UHAST stress. It is observed that all Cu9Al4 was consumed, while very little copper aluminide remained after 168 hours of UHAST stressing.

Unique Autoclave Stress Induced Failure Mechanism

2005 ◽  
Author(s):  
John Butchko ◽  
Bruce T. Gillette
Keyword(s):  
Corrosion Rate ◽  
Grain Boundary ◽  
Failure Analysis ◽  
Failure Mechanism ◽  
Metal Corrosion ◽  
Corrosion Mechanism ◽  
Reliability Testing ◽  
Process Change ◽  
Transistor Reliability ◽  
Pass Through

Abstract Autoclave Stress failures were encountered at the 96 hour read during transistor reliability testing. A unique metal corrosion mechanism was found during the failure analysis, which was creating a contamination path to the drain source junction, resulting in high Idss and Igss leakage. The Al(Si) top metal was oxidizing along the grain boundaries at a faster rate than at the surface. There was subsurface blistering of the Al(Si), along with the grain boundary corrosion. This blistering was creating a contamination path from the package to the Si surface. Several variations in the metal stack were evaluated to better understand the cause of the failures and to provide a process solution. The prevention of intergranular metal corrosion and subsurface blistering during autoclave testing required a materials change from Al(Si) to Al(Si)(Cu). This change resulted in a reduced corrosion rate and consequently prevented Si contamination due to blistering. The process change resulted in a successful pass through the autoclave testing.

Discussion of Oxygen Threshold Level for Corrosion Management in Seawater Injection Systems

2021 ◽  
Author(s):  
Jean Vicente Ferrari
Keyword(s):  
Corrosion Rate ◽  
Oxygen Reduction ◽  
Water Injection ◽  
Steel Corrosion ◽  
Threshold Level ◽  
International Standards ◽  
Limiting Current ◽  
Order Of Magnitude ◽  
The Impact ◽  
Oxygen Concentrations

Abstract Generally, in water injection systems, oxygen levels starting from around eight ppm are deoxygenated to below 50 ppm, following international standards' guidelines. This work aims to discuss the impact of such a magnitude value of oxygen contamination on steel corrosion in seawater injection systems by analysing theoretical polarisation curves and results from published works with different approaches. Corrosion models consider mass-transfer controlled diffusion of oxygen to predict the maximum steel corrosion rate, which depends on the oxygen limiting current, which in turn is strongly influenced by flow velocity. The effect of free chlorine on corrosion in seawater injection systems has also been considered and included in an oxygen equivalent parameter. In such systems, where oxygen reduction is the key cathodic reaction, the corrosion process may be under cathodic activation control, independent of flow at higher velocities or when erosion-corrosion begins. In this work, theoretical polarisation curves were constructed by using published oxygen and chlorine cathodic limiting currents (iLc) on carbon steel and a noble metal electrode, respectively. Aerated (200 ppb and 9000 ppb of oxygen) and deaerated conditions (50 ppb of oxygen) and the presence of 300 ppb of chlorine were applied to the assumed exchange current densities (io). Neutral (pH 7) and acid (pH 4) conditions (considering the presence of CO2) were also assumed to be at room temperature and pressure. Since the corrosion rate in lower oxygen concentrations (ppb order of magnitude) may result in corrosion rates of the same order of magnitude than in higher oxygen concentrations (ppm order of magnitude) when comparing and analysing results from experimental, semi-empirical or mechanistic approaches, it is necessary to weigh up the effects of both steel surface (bare or scaled/corrosion products) and flow. At oxygen concentrations below 200 ppb and under acid conditions, the contribution of H+ reduction on corrosion rate starts to be higher than oxygen reduction, mainly in the absence of chlorine.

Alloy Design of New Ni-Based Structural Materials for Electrolytic Reduction and its Corrosion Behavior in Lithium Molten Salt

2014 ◽  
Vol 886 ◽  
pp. 41-44 ◽  
Author(s):  
Sang Kyu Park ◽  
Tae Hyuk Lee ◽  
Moon Soo Sim ◽  
Jae Soo Noh ◽  
Soo Haeng Cho ◽  
...  
Keyword(s):  
Corrosion Rate ◽  
Molten Salt ◽  
Corrosion Behavior ◽  
Structural Materials ◽  
Solute Concentration ◽  
Inert Atmosphere ◽  
Electrolytic Reduction ◽  
Corrosion Products ◽  
Alloy Formation ◽  
Lithium Molten Salt

In this study, the corrosion behavior of new Ni-based structural materials was studied for electrolytic reduction after exposure to LiCl-Li2O molten salt at 650°C for 24-216h under an oxidizing atmosphere. The new alloys with Ni, Cr, Al, Si, and Nb as the major components were melted at 1700°C under inert atmosphere. The corrosion products and fine structures of the corroded specimens were characterized by SEM, EDS, and XRD. The corrosion rate of 12wt% Cr-2wt% Si alloys and 12wt% Cr-5wt% Si alloys are below 0.3mm/year. However, the corrosion rate of 20wt% Cr-5wt% Si is 0.6mm/year. Also, the corrosion products of 12wt% Cr alloys were Cr2O3, NiCr2O4, Ni, and NiO; those of 20wt% Cr alloys were Cr2O3, LiAl2Cr3O8, and NiO. The higher corrosion rate of 20wt% Cr-5wt% Si could be the higher solute concentration which leads to an unstable alloy formation. As confirmed by the pseudo binary phase diagram of (Ni-Cr-Al-Nb)-Si, the solubility of the silicon with 20 wt% of Cr decreased to 4 wt% from 5 wt% with 12 wt% of Cr.

scholarly journals Investigation of Corrosion Resistance Enhancement for Biodegradable Magnesium Alloy by Ball Burnishing Process

2020 ◽  
Vol 14 (2) ◽  
pp. 175-183 ◽  
Author(s):  
Chenyao Cao ◽  
Jiang Zhu ◽  
Tomohisa Tanaka ◽  
Dinh Ngoc Pham ◽  
◽  
...  
Keyword(s):  
Corrosion Resistance ◽  
Mass Loss ◽  
Immersion Test ◽  
Corrosion Products ◽  
Mg Alloys ◽  
Surface Finishing ◽  
Human Organism ◽  
Corrosion Mechanism ◽  
Ball Burnishing ◽  
Treated Sample

Magnesium and magnesium-based alloys are considered ideal materials for implants in orthopedic treatment because their stiffness is close to that of human bones, and they can be absorbed gradually in the human organism. However, a major issue in their actual application is that the corrosion speed of Mg alloys is very high in aggressive environments such as the human fluids. In previous studies, many approaches have been attempted to enhance the corrosion resistance of Mg alloys. In this research, ball burnishing, a mechanical surface finishing process, is applied to improve the corrosion resistance of Mg alloys by changing its surface properties. The influence of the burnishing parameters on the corrosion resistance is investigated, and the corrosion of a treated and non-treated sample are compared. The test material used is the AZ31 Mg alloy. Firstly, a comprehensive review of the effect of burnishing on the final microstructures is reported. The influence of burnishing on grain size, work-hardened layer thickness, crystal orientation, and residual stress of the sample is discussed. Secondly, by conducting an especially designed long-term immersion test, the mass loss and surface evolution of each sample are evaluated. The experimental results indicate that, under proper processing conditions, the mass loss of the treated sample (8.8 mg) can be reduced to 36% of the non-treated one (24.2 mg). To elucidate the mechanism behind corrosion resistance enhancement by burnishing, the samples treated with the optimal processing parameters found are immersed in an aggressive solution for 1, 3, 5, and 7 days. From the results of mass loss measurement and surface structure characterization, it was found that, among pitting, general, and intergranular corrosion, pitting corrosion is the dominant corrosion mechanism. The holes enlarge because pits combine together, representing the greatest portion of mass loss. The main mechanism enhancing corrosion resistance is the size reduction of the grains on the surface induced by ball burnishing, causing a denser distribution of corrosion products in the immersion test. These corrosion products protect the material underneath accelerated corrosion.

Polymer Injection to Unlock Bypassed Oil in a Giant Carbonate Reservoir: Bridging the Gap Between Laboratory and Large Scale Polymer Project

2021 ◽  
Author(s):  
Clement Fabbri ◽  
Haitham Ali Al Saadi ◽  
Ke Wang ◽  
Flavien Maire ◽  
Carolina Romero ◽  
...  
Keyword(s):  
High Salinity ◽  
Water Injection ◽  
Cross Flow ◽  
Carbonate Reservoir ◽  
Carbonate Reservoirs ◽  
Laboratory Work ◽  
High Permeability ◽  
Polymer Injection ◽  
Single Well ◽  
Pilot Design

Abstract Polymer flooding has long been proposed to improve sweep efficiency in heterogeneous reservoirs where polymer enhances cross flow between layers and forces water into the low permeability layers, leading to more homogeneous saturation profile. Although this approach could unlock large volumes of by-passed oil in layered carbonate reservoirs, compatibility of polymer solutions with high salinity - high temperature carbonate reservoirs has been hindering polymer injection projects in such harsh conditions. The aim of this paper is to present the laboratory work, polymer injection field test results and pilot design aimed to unlock target tertiary oil recovery in a highly heterogeneous mixed to oil-wet giant carbonate reservoir. This paper focuses on a highly layered limestone reservoir with various levels of cyclicity in properties. This reservoir may be divided in two main bodies, i.e., an Upper zone and a Lower zone with permeability contrast of up to two orders of magnitude. The main part of the reservoir is currently under peripheral and mid-flank water injection. Field observations show that injected water tends to channel quickly through the Upper zone along the high permeability layers and bypass the oil in the Lower zone. Past studies have indicated that this water override phenomenon is caused by a combination of high permeability contrast and capillary forces which counteract gravity forces. In this setting, adequate polymer injection strategy to enhance cross-flow between these zones is investigated, building on laboratory and polymer injection test field results. A key prerequisite for defining such EOR development scenario is to have representative static and dynamic models that captures the geological heterogeneity of this kind of reservoirs. This is achieved by an improved and integrated reservoir characterization, modelling and water injection history matching procedure. The history matched model was used to investigate different polymer injection schemes and resulted in an optimum pilot design. The injection scheme is defined based on dynamic simulations to maximize value, building on results from single-well polymer injection test, laboratory work and on previous published work, which have demonstrated the potential of polymer flooding for this reservoir. Our study evidences the positive impact of polymer propagation at field scale, improving the water-front stability, which is a function of pressure gradient near producer wells. Sensitivities to the position and number of polymer injectors have been performed to identify the best injection configuration, depending on the existing water injection scheme and the operating constraints. The pilot design proposed builds on laboratory work and field monitoring data gathered during single-well polymer injection field test. Together, these elements represent building blocks to enable tertiary polymer recovery in giant heterogeneous carbonate reservoirs with high temperature - high salinity conditions.

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