Subsea oil and gas production systems can be subject to Hydrogen Induced Stress Cracking (“HISC”) depending on the material, cathodic protection and other factors. A failure in this kind of systems can lead to safety issues as well as environmental hazards and high repair costs. The analysis of recent failures has led to the recognition of HISC as a very important issue related to local stress and strain. This has necessitated the extensive use of Finite Elements Methods for the analysis of all system components. Since HISC is a recent issue, there are very few cases of such assessments reported in the literature. This paper is based on the assessment of the susceptibility of subsea piping manifolds of Duplex stainless steel to Hydrogen Induced Stress Cracking, which was conducted during the Skarv project by General Electric Oil & Gas. A variety of cases consisting of different loads and configurations were considered to give a broad assessment using a recently developed code (DNV-RP-F112-October2008). This work has led to the development of a set of procedures and models for the assessment of the entire system which is described in the current paper. The proposed methodology is useful for both design purposes and also for the verification of parts, which, if found to be non-compliant, would require redesign. In general, parts that were determined to be non-compliant using a linear assessment were found to be compliant through non-linear analysis, in fact 3D plastic analysis leads to a redistribution of stress and strain and hence, to lower values. “Cold creep” was not considered since the levels of stress and strain were considered to be low enough to avoid this phenomenon. As a consequence of this experience, a new methodology was developed, which is able to speed up the analysis process and to predict local stresses from only pipe elements. The latter permits the use of a linear assessment for bends, T junctions and weldolet even with misalignment and erosion, avoiding the need to perform 3D analysis. The second part of the paper describes this method.

The Gas Turbine manufacturers are continuously engaged in providing to their customers machines with higher performances, longer lives, better reliability and availability. Since the late 70’s, the gas turbines are designed by using computational tools able to simulate through physic based models the thermal and mechanical behavior of the engines by predicting with high accuracy gas turbine internal pressures, temperatures, stresses etc., across the full flange to flange architecture; but it is only in the last one or two decades that computational predictions have done a huge step forward thanks to the great progress of the information technology. What was before designed with a worst case deterministic approach, it is now designed through optimization, by assessing many different configurations and it is made robust through sensitiveness and statistical assessments. One further step forward has been made possible by new software tools able to manage simulation process flows made of a variety of applications, including commercial CAD/CAE software, in house software and Excel spreadsheets. The simulation process described in this paper has been developed for rotor life assessments and the proprietary company is currently using the process to manage part of its heavy duty gas turbine fleet engaged in the oil and gas application for the estimation of risk to extend rotor life beyond inspection interval [1].

The paper will describe the main outcomes of a risk assessment performed by General Electric O&G (GE O&G) in 2013 on a large number of gas turbine rotors that had exceeded their design end of life (EOL). The assessment involves a large number of medium frames (e.g. MS3002J, MS5002C) plus small industrial gas turbines (e.g. MS1002, PGT10). The design end of life is the lifespan inside which the risk of uncontained failure is expected to be improbable and this means the failure has a probability of occurrence of 0.12 total events or less during the life of five hundred gas turbines operating 8000 hours per year for 30 years [1]. GE gas turbine rotors are designed to operate with no need of inspection and maintenance till their design EOL (alias serviceable life). The gas turbines end users may exceed EOL, provided the rotors have been subjected to a specific investigation that includes teardown and a full inspection. The disregard of this recommendation may have catastrophic consequences on the gas turbines and on surrounding equipment and personnel. Such recommendation was provided to customers the first time in 2005 through GETIL 1576 [2], the recommendation was renewed in 2013 with a new communication NIC 13.16 [3]. The risk assessment has essentially focused on rotating parts, because rotors (i.e. shaft, wheel, spacer) are the highest gas turbine energy components, that even if designed with high safety margins, they are not immune from time (e.g. creep) and/or cyclic dependent damage (e.g. fatigue). The assessment has been carried out by following MIL-STD-882C [1] guidelines and in accordance to the principles defined by ISO 12100-2010 [4]. The failure risks have been estimated with the help of specific tools by using field data and life calculations performed with physics-based models. The paper describes the methodology used to support the risk assessment and this means the “rotor life management methodology” that was developed by GE more than ten years ago, and was subsequently improved by including statistical assessments.

This paper describes the test rig and the functional tests that have been carried out to define a satisfying solution for the bearing #2 of NovaLT16, the GE Oil & Gas latest high-efficiency Gas Turbine. The bearing #2 is a journal bearing located inside the compressor discharge casing and for this reason it is exposed to high temperatures. As a consequence, the lube oil provided to the bearing should not only lubricate the bearing pads but also cool the bearing housing and for this reason it should be more than what required by the pads. This large amount of oil is gathered by two bearing housing sumps and then drained by gravity through two pipes. Scavenge pumps are not required. The bearing housing also includes two circumferential labyrinth seals able to prevent oil leakage through the gap between the bearing housing and rotor. Both seals are purged by air extracted from the gas turbine compressor; the air not only creates a barrier to oil leakage but facilitate the draining inside the sumps. An insufficient draining system may increase the oil levels in the bearing housing sumps above the safety limit and therefore it may generate oil leakage through the labyrinth seals. If the leakage reaches the external high-temperature zone then it can lead to oil degradation, decrease in GT performances and engine tripe due to smoke in the GT package in the worst case. The draining system was therefore tested with an advanced test rig. The test rig was a 1:1 scale including the bearing housing, the bearing with its pads and also a mock-up of the shaft. The shaft was driven by an electric motor and therefore it was possible to verify the full operating speed range of the gas turbine. The gas turbine discharge compressor casing environment was simulated through electric resistances able to provide heat all around the bearing housing. During the functional tests there have been simulated design and off-design conditions including extreme values of oil pressure, oil temperature, pitch and roll angles (for offshore application), shaft speed and buffering air. The results were mainly evaluated in terms of sump oil levels, shaft temperatures and bearing housing temperatures. The full test campaign allowed to identify and validate a satisfying configuration both for on-shore and off-shore applications and to properly tune all the main bearing parameters in order to guarantee a robust configuration. The NovaLT16 test campaign is part of the continue evolution in the GE O&G bearing #2 area design, started with the previous gas turbines (such as MS5002E and GE10).

One of the possible constraint configuration of an annular combustion chamber in a gas turbine is by means of radial pins. Radial pins usually connect the outer turbine casing to the combustor dome and fix combustor axial and circumferential displacements while allowing combustor free radial deformation, under thermal loads. In the typical mounting scheme, radial pins are screwed on the outer casing and then inserted into dedicated housing holes on the dome. Because of this arrangement the force (introduced by mechanical, thermal and dynamic loads) reacted by each pin is inherently not deterministic since it depends on the actual gap between the pin itself and the housing bush on the dome, which, in turn, is not explicitly known, being a function of the overall tolerance stack up. The scope of this study was to develop a method to design the radial pins of NovaLT™16 (*) combustion chamber, applicable since the conceptual phase, using a probabilistic approach [7]. Actual pin-bush gap distribution is calculated from stack up analysis and then used as input for a numerical simulation which computes the distribution of the reaction force on each pin, as a function of number of pins, stiffness of the pin, gap between pin and bush. Two different arrangements have been considered: the classic scheme and the floating pin configuration. The new probabilistic design approach allowed to have a robust understanding of the force distribution within the whole set of pins, to compute the optimal combination of pin number, pin stiffness, and gap and ultimately to select the floating pin configuration as the one to be implemented in NovaLT16 combustor. Test results revealed pin contact distribution was in line with predictions.