Analysis and Evaluation on Residual Strength of Pipelines with Internal Corrosion Defects in Seasonal Frozen Soil Region

In order to study the residual strength of buried pipelines with internal corrosion defects in seasonally frozen soil regions, we established a thermo-mechanical coupling model of a buried pipeline under differential frost heave by using the finite element elastoplastic analysis method. The material nonlinearity and geometric nonlinearity were considered as the basis of analysis. Firstly, the location of the maximum Mises equivalent stress in the inner wall of the buried non-corroded pipeline was determined. Furthermore, the residual strength of the buried pipeline with corrosion defects and the stress state of internal corrosion area in the pipeline under different defect parameters was analyzed by the orthogonal design method. Based on the data results of the finite element simulation calculation, the prediction formula of residual strength of buried pipelines with internal corrosion defects was obtained by SPSS (Statistical Product and Service Solutions) fitting. The prediction results were analyzed in comparison with the evaluation results of B31G, DNV RP-F101 and the experimental data of hydraulic blasting. The rationality of the finite element model and the accuracy of the fitting formula were verified. The results show that the effect degree of main factors on residual strength was in order of corrosion depth, corrosion length, and corrosion width. when the corrosion length exceeds 600 mm, which affects the influence degree of residual strength will gradually decrease. the prediction error of the fitting formula is small and the distribution is uniform, it can meet the prediction requirements of failure pressure of buried pipelines with internal corrosion defects in seasonally frozen soil regions. This method may provide some useful theoretical reference for the simulation real-time monitoring and safety analysis in the pipeline operation stage.

Significance of Smart and Integration System Solutions in Maintaining Well Integrity

Well integrity is one of the most critical elements for extending the producible life of a well. A healthy well enables optimization of productivity, enhanced oil recovery, trial tests of new technologies, and much more. Factors such as external corrosive aquifers, internal corrosion, corrosive hydrocarbons, cement bond damage, solids and sand production, and others are considered the main integrity dangers worldwide. When well integrity is affected, not only economic risks but also risks to health, environment and safety are probable. Well integrity is an objective achieved by optimum design and construction of the well after studying and assessing all possible hazards; effective monitoring of the well behavior while it's under production; and timely intervention when an integrity problem is detected. Evaluating all the aspects of well integrity during well operation is crucial. Cyclic surveillance is important to be followed, including wellhead pressures/annuli surveys, temperature surveys, corrosion logs, wellbore clearance, and well fluid samples, among other activities. With the help of smart and integrated systems, production engineers can have much better control over well integrity and be proactive in making timely decisions prior to any unforeseen events. The smart system keeps the well surveillance records, risk-rank the wells, and sets KPIs to tackle necessary actions wherever applicable. The developed system immediately triggers any threat on well integrity when it occurs.

Corrosion Mitigation Using Nonmetallic Piping for In-Plant Hydrocarbon Service

The underground hydrocarbon metallic lines are usually subjected to severe corrosion due to several reasons such as high water table in the area and due to intermittent bi-directional crude service or similar environmental factors. To meet the challenge, non-metallic underground crude transfer lines may be considered to carry oil from/to the bulk storage sites. Since there are not many non-metallic applications in HC services, it may become a challenge to get the necessary approvals from the various stake holders in terms of concerns for asset integrity and the costs. This report details the conversion of metallic crude pipeline application to a non-metallic one. Normally, the in-kind replacement will involve an internally coated CS line to reduce corrosion rate. However, engineering studies and assessments reveal that there are greater economic benefits when adapting to a non-metallic counterpart. For a generic case, hydraulics on a 1.7km crude transfer line with 48" diameter and the intermittent crude service revealed that 36" non-metallic version could do the job with less installation costs as minimal site activities will be required and there will be no requirements of non-destructive tests (NDT). Only a service test following the installation may be necessary to prove the operational integrity. Cost comparisons showed a 28% less project cost in using the non-metallic pipeline while meeting all other application requirements. The introduction of non-metallic line would take away the problem of the external and internal corrosion from the equation. Especially in the aging facilities where fatigue becomes an issue, the carbon steel line always requires additional maintenance activities and there was always a chance to develop an underground pin hole. Therefore, an extensive inspection program had its own costs to maintain the line. With the non-metallic pipe usage, not only the construction costs can be lowered but it could avoid major inspection and maintenance program costs. The Nonmetallic line is considered low to maintenance free, and additional long-term savings are expected. This application opens the door for the utilization of nonmetallic material in plant hydrocarbon processes. And given the size considered of this line (36 inches), this allows for further consideration to install nonmetallic piping on a wide range of applications. Also, non-metallics are especially effective for sluggish or intermittent flows and areas with high water table to avoid all sorts of erosion and corrosion issues internally due to process conditions or externally due to environmental conditions.

SPECIFICS OF DIAGNOSTICS OF TECHNICAL CONDITION OF TRANSPORT AND TECHNOLOGICAL SYSTEM “MINING GAS PIPELINE – MINE WORKING”

The purpose of the paper is to analyze a deformation mechanism of the mine degassing pipelines to forecast their spatial changes in terms of intensification of underground mining of coal-gas seams. Methodology. The paper deals with expert assessment of the available approaches to diagnostics of technical condition of mine degassing pipelines, which are constructed within the in-seam underground mine workings with the floor rocks prone to heaving. The results of scheduled surveying measurements of technical condition of in-seam development workings have helped identify the potentially hazardous zones of rock mass deformation and indices of changes in spatial location of section degassing pipelines mounted in those mine workings. To determine the operating modes of a degassing pipeline under such operating conditions, a computer model of interaction of the elements of transport-technological system “mine gas pipeline – mine working” has been developed Findings. Diagnostics of technical conditions of the mine gas transmission lines and examination of their dismantled components have helped understand that deflections, mainly resulting in water accumulation zones, intensive corrosion of internal pipe walls, and mechanical depositions of coal and rock dust take place right within the flange connection areas. Formation of such zones is argued by health of the degassing pipeline as well as mine air inflow. Availability of internal corrosion, water accumulations, and mine air inflow decreases substantially capacity of the underground gas transmission line inclusive of qualitative characteristics of the captured methane-air mixture and efficiency of MDS on the whole. Originality. New approaches to diagnostics of technical condition of mine degassing gas pipeline in difficult mining and geological conditions of development of gas-bearing coal seams are substantiated and it is offered to consider indicators of their functioning as interacting in space and time transport-technological system "mine gas pipeline - mining". Practical implications. The operational parameters of mine degassing systems notes that the equipment performance with the least underpressure losses created by vacuum pipes requires that the degassing pipeline should have minimum hydraulic resistance of the gas transmission network. Pipeline aeration from the mine workings and water accumulations should be prevented by means of qualitative hermetic sealing of its flange connections as well as the pipeline straightness with the corresponding pitches. Consequently, the basic requirements for operating mine degassing pipelines involve their design profile, tightness of flange connections of pipes as well as operative control of the facility health.

Life Prediction of Crude Oil Pipeline to Mitigate Leakages: A Case Study of an NPDC Major Pipeline in OML30, Nigeria

Pipeline leak or failure is a dreaded event in the oil and gas industries. Top events such as catastrophes and multiple fatalities have occurred in the past due to pipeline leak or failure especially when loss of contents was met with fire incidents. It is therefore imperative that the causes of pipeline failure are tackled to prevent or mitigate leak incidents. This is expedient to curb the menace that goes with leak incidents, such as destruction of the environment and ecosystem; loss of assets, finance, lives and property; dangers to workers and personnel, production downtime, litigation and dent to company’s reputation. This work focuses on the investigation of the actual cause of sudden pipeline failures and frequent pipeline leaks that often result to sectional pipeline replacement before the expiration of their anticipated life cycle in OML30 oil and gas field. The pipeline material selected, the standard of the minimum wall thickness of the material, the corrosive nature of the pipeline content and the observed internal corrosion rate were probed. An analysis of the rate of thinning and diminution of the internal wall of the pipeline by monitoring the interior rate of corrosion was used to forecast the remaining life of a crude oil pipeline and predict the life expectancy of a newly replaced or installed pipeline or installed pipeline.

Experimental Investigation of the Ash Deposition Characteristics of Biomass Pretreated by Ash Removal during Co-Combustion with Sub-Bituminous Coal

Although replacing biomass, (e.g., wood chips and pellets), with thinning wood and herbaceous biomass is eco-friendly and economically advantageous, their direct utilization in plant boilers is associated with ash-related challenges, including slagging and fouling. The aim of this study is to determine the effects of ash removal treatment (ashless biomass (ALB)) in the context of solid fuel power plant boilers. Ash was removed via neutralization of metal ions and carboxylic acids contained in the biomass ash. The ash removal rate of K, Na, Cl was indicated by assessing the total biomass before and after ash removal treatment, via XRF analysis. Co-combustion with sub-bituminous coal and ALB-treated biomass was analyzed using a drop tube furnace and revealed that NOx and SOx values converged converge toward an approximate 10 ppm error, whereas the Unburned Carbon (UBC) data did not exhibit a specific trend. Factors associated with slagging and fouling, (capture efficiency (CE), and energy based growth rate (GRE)) were calculated. All biomass samples without pretreatment exhibited V-shaped variation. Conversely, for ashless biomass (ALB) samples, CE and GRE gradually decreased. Thus, the ALB technique may minimize slagging and fouling in a boiler, thus, reducing internal corrosion associated with ash deposition and enhancing the economic operation of boilers.

Velocity compensation and practical aspects for high-temperature ultrasonic testing

Increasingly, the need for on-stream asset integrity, where inspections are carried out while components are still operating to reduce the disruption and impact of outages, is required at elevated temperatures. For example, a typical hydrocarbon refinery has process units with surface temperatures in excess of 500°C, where internal corrosion of the typically steel components needs to be monitored by testing, to maintain safe and reliable operation. This is ubiquitously carried out by means of ultrasonic testing (UT). As high-temperature tools increasingly become available, the accuracy of thickness measurements is often questioned due to the intrinsic link between the measured time-of-flight (TOF) and the characteristic speed of sound of the material. The velocity, in turn, is a factor of the elastic modulus of the material, which is inversely proportional to temperature in steel. Historically, international standards and practices publish correction factors for generic steel materials, but increasingly the desire for more accurate determination is required with more advanced tools and techniques. Here, the velocity as a function of temperature is determined through experimental study for two common carbon steels that may see service at elevated temperatures, and the correction factor is shown by application to a typical corrosion mapping survey at elevated temperature. The errors associated with variable velocity are shown to be effectively minimised below the normal variability of ultrasonic testing.