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The demand for ensuring the reliability and accuracy of drilling sensor data is rapidly increasing with the rise of data analytics and automation. Proven systems engineering methodologies used in the aerospace industry offer the drilling industry a solution for assuring the reliability of sensor data and software processing of this data. This paper describes an approach for verification and validation (V&V) of sensors and systems leveraging experiences from the aerospace industry. Both oil and gas (O&G) and aerospace have high-value assets where failures can lead to significant loss of life and huge financial impacts. Commercial aviation, in particular, has achieved a remarkable improvement in safety over many decades through design standards requiring functions be precisely defined and their implementation be verified against those requirements. Avaition industry standards, such as DO-178C for Software Considerations in Airborne Systems and Equipment Certification, acknowledge that not all aircraft systems require the same attention. The standards define a range of classification from the most critical, such as autopilots, to the least critical, such as entertainment systems. This paper describes how mapping levels and requirements from DO-178C to oil and gas can assist in the improvement of data quality to the higher standards now required in drilling operations. A range of criticality provides the ability to seek a balance of costs vs. benefits for application to drilling systems to achieve the needed data quality.
Brady, Jerry (Brady Technologies of Alaska) | Passmore, Kevin (Halliburton) | Paskvan, Frank (BP) | Wilkes, Jason (Southwest Research Institute) | Allison, Tim (Southwest Research Institute) | Swanson, Erik (Xdot Engineering and Analysis) | Klein, John (Roto-Therm Incorporated)
This is the first time a compressor and turbo expander have been built small enough to be run through tubing and operated autonomously from the surface. A brief review of the overall system design and critical component design and testing are followed by a detailed review of the surface testing of the entire prototype machine at simulated downhole conditions. The SPARC concept uses the excess production pressure (energy) that is usually wasted across a choke or elsewhere in the production system to generate power through a downhole turbo-expander that runs a downhole gas compressor to reinject a portion of the gas stream. The system consists of a downhole separator, compressor, turbo-expander and other standard downhole equipment for the necessary plumbing. The successful test results of the bearing and thrust disk component testing at up to 1,000 psig and 450 F are provided, followed by the successful yard test results of the entire SPARC prototype machine at downhole flowing conditions, including all the rotating equipment (turbo expander, compressor, and shaft), in situ process-lubrication system, and autonomous controls.
Nibur, Kevin A. (Hy-Performance Materials Testing, LLC) | Somerday, Brian P. (Southwest Research Institute) | Pillot, Sylvain (Industeel, ArcelorMittal) | Gangloff, Richard P. (University of Virginia)
The resistance of bainitic 2¼Cr-1Mo-0.3V plate to internal hydrogen assisted cracking (IHAC) and hydrogen environment assisted cracking (HEAC) has been measured, and the results explained by consideration of hydrogen trapping at nanometer-size VC precipitates. Precracked specimens were tested, both with and without thermal-H2 precharging, under slow-rising loading in either moist air or gaseous hydrogen at 0.3 MPa to 100 MPa. Regarding IHAC, both the initiation threshold stress intensity and stable crack growth resistance were substantially above values typical of IHAC in conventional 2¼Cr-1Mo steel. The crack initiation threshold of 2¼Cr-1Mo-0.3V under HEAC conditions was much lower and was similar to that of 2¼Cr-1Mo without VC precipitates. Analytical calculations of H-trap occupancy using Oriani’s equilibrium trapping theory qualitatively predict these experimental results.
Understanding hydrogen trapping thermodynamics and kinetics is fundamental to interpreting hydrogen embrittlement. Different applications may experience different hydrogen-source boundary conditions. For example, hydrogen precharged mechanical test specimens may be considered as a closed system since the total internal hydrogen concentration is fixed (Hirth, 1980) but can vary in partitioning between lattice and trap sites. In contrast, specimens which are stressed in gaseous hydrogen behave as an open system since the lattice hydrogen concentration is continuously sustained by the external hydrogen source, and trap concentrations are not limited by hydrogen supply from lattice sites. Since these boundary conditions affect hydrogen trapping, the effect of hydrogen source must be considered for hydrogen embrittlement in structural design.
Refinery operations use heavy wall Cr-Mo steel pressure vessels for hydroprocessing reactions involving exposure to moderately high temperature and hydrogen pressure for long periods of time. Hydrogen embrittlement is typically not a significant concern during elevated temperature operations. However, during periods of shutdown, the reactor walls may experience stress due to both hydrogen pressure as well as thermal gradients, while the reactor is cooled into the temperature range where the steel is susceptible to hydrogen embrittlement. Weld residual stress may also be present. Design of the thermal and pressure profiles during shutdown must be informed by measurements of subcritical cracking thresholds due to both internal and external hydrogen to prevent cracking during shutdown and startup.
Trillo, Elizabeth (Southwest Research Institute) | Duret-Thual, Claude (French Corrosion Institute) | Thierry, Dominique (French Corrosion Institute) | Mendibide, Christophe (French Corrosion Institute) | Salvatori, Ilaria (RINA Consulting) | Alleva, Laura (RINA Consulting) | Martin, John. W. (JWM Materials Consulting)
Within the framework of a Joint Industrial Project (JIP) sponsored by several petroleum companies, the behavior of several Precipitation Hardened (PH) Ni-based alloys with respect to Hydrogen Induced Stress Cracking (HISC) resistance was studied using the Slow Strain Rate Tensile (SSRT) test method under hydrogen charging conditions. The experimental conditions included a 0.5M sulfuric acid solution at 5 mA/cm2 and at 40°C at a strain rate of 10−6 sec−1. A round robin was performed that highlighted the need to measure the effective strain rate of the specimen during the elastic part of the SSRT test, the cell configuration, the current density, the gas cap composition, were all studied to determine the effects on the results. Once the test conditions had been optimized, the study of different industrial heats was carried out on specimens sampled in three locations, 120 degrees apart and at mid radius. It was found that sampling different areas could lead to changes in the test results, resulting mainly from microstructural variances at different locations of the bar. The results generated in this program could then be studied by relating plastic elongation obtained under CP as well as cracking mode and microstructure compliance with the API 6A CRA standard.
Precipitation Hardened (PH) Ni base alloys have been used in oil and gas high pressure high temperature conditions due to their high strength and high corrosion resistance capabilities. However, under such conditions they are known to be susceptible to hydrogen embrittlement. Indeed, there have been reported a number of PH Ni Alloy failures that could be due to Hydrogen Induced Stress cracking (HISC)1-3. The failures were of different N07718 alloys, however, there was a need for industry to identify which heats of these PH Ni alloys would result in HISC failures.
An assessment was carried out to look at heats of N07718 material with different microstructures, as defined by API 6A CRA4 and API 6A 7185. These standards specify the acceptable and not acceptable microstructures based on the optical micrographs. Acceptable microstructures have only a small amount of grain boundary precipitates, whereas not acceptable microstructures have a large amount of grain boundary precipitates. A set of optical micrographs are provided for each case and material in the API 6A 718 (and 6A CRA) standards for comparison. Yet, although the microstructures seem to imply cracking resistance, it is not a direct measure of embrittlement behavior.
Trillo, Elizabeth (Southwest Research Institute) | Dante, James (Southwest Research Institute) | Chambers, Brian (Shell P & T Technology) | Gonzalez, Manuel (Shell P & T Technology) | Somerday, Brian (Southwest Research Institute) | Miller, Michael A. (Southwest Research Institute) | Long, Xin (Shell P & T Technology)
Oil Country Tubular Goods (OCTG) high strength steels are susceptible to hydrogen assisted cracking (HAC) due to hydrogen ingress as a result of exposure to environmental conditions (cathodic protection (CP) and/or H2S environments) and as such are prone to failure. In order to address the potential cracking susceptibility, a study was performed to understand fundamental parameters such as steady state hydrogen permeation flux, hydrogen concentrations and hydrogen trap binding energies of the high strength steel under charging conditions. Electrochemical permeation testing was performed on unstressed and 80%AYS stressed C110 pipe steel using an applied charging current density of 0.5 mA/cm2 in a 0.5M H2SO4 test solution at 75 F. Comparisons between the stressed and unstressed samples showed that there were no significant differences in steady state flux (Jss) and calculated hydrogen concentration for this charging condition. Further testing was performed to measure hydrogen uptake and time to saturation under the same charging conditions using the Silicone Oil Method. Subsequent laser thermal desorption mass spectrometry (LTDMS) was performed at the saturation point and at several temperature scan rates in order to calculate the apparent activation energy for hydrogen desorption, from which the binding energy for trap sites can be inferred (Eb).
As higher material strengths are needed for ever increasing deeper wells, then the necessity of understanding the hydrogen assisted cracking (HAC) regimes for high strength casing materials (P-110 and C-110 type casings) are ever needed. These materials are often under a cathodic potential environment or H2S environment, whereby hydrogen ingress may be possible, thereby increasing the susceptibility to HAC.
Thus, the hydrogen ingress and transport into a material needs to be understood in order to effectively characterize a material’s resistance to HAC. The subsurface hydrogen concentration is an important parameter that can be quantified from permeation testing through the effective diffusivity (Deff) of hydrogen in a material and breakthrough times according to ASTM G1481
Where L is the sample thickness and tb is the breakthrough time determined by extrapolating the linear portion of the rise transient to its intersection with the baseline oxidation current (nominally zero flux, i.e. J=0). Subsurface concentration (C0app) of hydrogen is calculated using:
where JSS is the steady state flux.
Martensitic stainless steel (UNS S41000), austenitic stainless steel (UNS S31000), and nickel-based alloy (UNS N06625) specimens were exposed at 450°C and 7.6 MPa in pure supercritical CO2 (sCO2) for two months. The exposure was performed in order to assess the effect of various variables on the oxidation of materials that may be used in oxy-combustion gas turbine systems using supercritical CO2. While variables such as temperature, coatings, contaminants, and pressure have been covered in the literature, other variables of potential interests, such as welding, stress corrosion cracking, galvanic issues, or crevices have not yet been studied. The impact variables on oxidation in high temperature sCO2, based on real life engineering designs, were assessed during this exposure.
Welding is considered to be of interest due to changes to the local microstructure at high temperature in the vicinity of the weld. Chromium diffuses to the grain boundaries, leaving a chromium-depleted area in the matrix nearby, resulting in a potential decrease in corrosion resistance. Galvanic corrosion may be an issue when nickel alloys and stainless steel are connected. It has been suggested in the literature that galvanic corrosion may not be an issue because sCO2 is not considered an electrolyte, but it has not yet been confirmed experimentally. Stress corrosion cracking might be an issue combining the oxidation occurring in sCO2 and the high pressure present, leading to accelerated crack growth of a susceptible material due to its microstructure.
All martensitic stainless steel specimens (plain, welded, or coupled) had a matt black surface finish after the two months exposure. The austenitic stainless steel and the nickel alloy were both discolored after the exposure. Mass gain inspection of the specimen was performed before and after exposure. The highest mass gain was found for the martensitic stainless steel, ten times higher than the austenitic stainless steel and nickel alloy. The welded specimens of martensitic and austenitic stainless steels showed mass gains up to 50% higher than for the non-welded specimens. The mass gains of the coupled materials (galvanic coupling or similar crevice coupling) were not different from that of the single specimens but significant corrosion bonding was observed in all couples. None of the U-bend martensitic stainless steel specimens showed signs of cracking.
Exposure temperature has a known effect on sulfide stress cracking (SSC) in low alloy steels where elevated temperatures permit the use of oil country tubular goods (OCTG) in sour conditions that would not be survivable at lower temperatures. In order to assess SSC susceptibility, NACE MR0175 / ISO15156-2 and API 5CT advise or require the use of room temperature NACE exposure tests in H2S-containing brines and, consequently, the bulk of qualification data on OCTG has been obtained at these conditions. Previous publications have demonstrated the effect of lower temperatures, e.g. 40°F, testing on KISSC values of low alloy steel using double cantilever beam (DCB) tests showing a reduction on sour toughness when the temperature is lowered from 75°F to 40°F. This KISSC data provides a clear indication of SSC severity at 40°F on crack propagation; however, very little data is available pertinent to crack initiation at temperatures lower than 75°F.
In this work, several crack initiation tests were performed in mild sour conditions and demonstrated that at low temperature crack initiation susceptibility is increased. Details of the results are discussed within the context of traditional SSC qualification tests and materials selection standards along with the theoretical understanding of SSC fundamentals. Cracking tendency and time-to-failure are reviewed within the context of environmental and material parameters that are altered by the exposure temperature including hydrogen diffusion, corrosion rate, dissolved H2S concentration, and the behavior of hydrogen traps.
Oil country tubular goods (OCTG) are utilized in well construction and completion in the oil and gas industry primarily to enable the flow of hydrocarbons and provide barriers between those fluids and the external environment. Resistance to environmentally-assisted cracking (EAC) is required in order to maintain the integrity of the OCTG for these reasons. For carbon and low alloy steel (LAS) OCTG materials, the dominant EAC concern is sulfide stress cracking (SSC), caused by hydrogen embrittlement in low pH H2S-containing aqueous conditions in the well. Well materials are exposed to a range of temperatures where the reservoir is typically significantly above room temperature and the wellhead is associated with the surface conditions at the well site. For subsea wells, particularly those in deepwater, the wellhead exposure temperature is typically 40°F (4°C).
There is a significant use of Nickel based alloys in the oil and gas industry for high strength / high corrosion resistance applications, yet there has been a lack of understanding of fracture toughness of these Ni alloys under seawater / Cathodic Protection (CP) environments. Furthermore, this class of alloys has demonstrated a weakness following high profile failures where the failing mechanism identified was Hydrogen Assisted Cracking (HAC). This study examines several Precipitation Hardened (PH) Nickel alloys by the J-R Curve method (ASTM E1820) using side-grooved single edged notched bend (SENB) fatigue pre-cracked test samples in a simulated seawater environment under CP. The Ni alloys evaluated, a good representation of those associated with the in-service failures reported in the past, were UNS N07718, UNS N07716 and UNS N07725 together with other alloys, more recently developed, such as UNS N09945 and UNS N09955.
The materials were tested in a 3.5%NaCl solution with applied potentials of −1.1V and −1.4V vs SCE at room temperature at a loading rate of 0.005 Nmm−3/2. The overall response of the alloys in laboratory air was elastic-plastic in nature while the behavior in environment shifted towards a linear-elastic response most likely associated with the embrittlement caused by the hydrogen adsorbed during CP. Scanning electron microscopy analysis was performed to obtain insights on the fracture morphologies. Amongst the alloys tested, UNS N07718 showed the least reduction in fracture toughness in the environment in relation to air while alloy UNS N07716 and N07725 showed the most susceptibility to the environment with the lowest performance.
The Oil and Gas industry has turned to Nickel alloys, especially precipitation hardened (PH) Nickel alloys, for subsea applications where high strength, high corrosion resistance, as well as cracking resistance are needed to be sufficiently operational in these applications. These Ni alloys are mainly but not only utilized where newer wells are encountering pressures above 15,000 psi and temperatures above 350°F.
Although Nickel alloys are needed for these high pressure high temperature (HPHT) applications, there have been known field failures with PH Ni alloys, such as UNS N077181-4. Many of these field failures have been linked to specific microstructural features. In particular, the presence of sufficient amounts of delta phase precipitation at the grain boundaries leads to intergranular cracking in UNS N07718 materials. Thus, although high strength makes these nickel alloys attractive, it may also make them more susceptible to hydrogen embrittlement.
The selection of a coating for suitable use on the exterior of a pipeline is an important consideration due to the safety and cost consequences of potential corrosion. Because there are numerous fusion-bonded epoxy (FBE) coating systems available for subsea pipelines under cathodic protection, the selection of the optimum coating system is critical to extend the integrity of oil and gas facilities. This paper discusses some of the laboratory screening tests, such as the long-term ageing in hot-water at 75, 95, and 112 °C complemented with cathodic disbondment, mechanical, and thermal tests, involved in the qualification process of various FBE coatings. Free standing films of the FBE coatings immersed in hot water at 75, 95, and 112 °C were also performed to determine water absorption for up to 90 days. Based on the qualification results and following a set of engineering guidelines, a weighted ranking for each test and coating type was constructed to determine the best coating performers. Coating performances were assessed as well as the potential failure mechanism/s of pipeline coatings under cathodic protection with a commentary regarding testing variables that may influence the test results and account for differences with field performance.
A fusion-bonded epoxy (FBE) is a one part, heat curable, thermosetting epoxy resin powder that utilizes heat to soften and adhere to a metal substrate. Typically, FBE coatings exhibit excellent adhesion to steel, good chemical resistance, resistant to abrasion, low oxygen permeability, and good flexibility.1,2 This combination of properties makes FBE an ideal choice as a protective coating under a wide variety of environmental conditions. The application of an FBE coating involves substrate preparation (cleaning and grit-blasting), heating of the metal substrate to the required temperature via induction and depositing the FBE powder via an electrostatic spray process. For most applications, optimal coating performance is achieved with thicknesses of ∼0.45 mm. To develop specific properties, pipeline owners sometimes stipulate increased FBE thickness (as much as 1 mm). This thickness increase improves both damage resistance as well as high temperature cathodic disbondment.
Caseres, Leonardo (Southwest Research Institute) | Dante, James (Southwest Research Institute) | Bocher, Florent (Southwest Research Institute) | Troconis, Brendy Rincon (The University of Texas at San Antonio) | Ynciarte, Vinicio (The University of Texas at San Antonio)
Corrosion of carbon steel in the presence of H2S is an important topic in the oil and gas industry that has been studied for more than fifty years. Removing this compound results in not only an increase in the corrosion resistance of carbon steel, but also an improvement of environmental, health and safety compliance, thereby increasing production efficiency. Triazines are commonly used as H2S scavengers. However, failures in the form of stress corrosion cracking (SCC) have recently been reported when using certain triazines making it necessary to understand the failure mechanism in order to mitigate/control this detrimental phenomenon. It has been suggested that SCC is governed by corrosion processes and specifically by the transition from a passive (more protective) surface to an active (less protective) surface. This transition is a complicated function of acid gas concentration (CO2 and H2S) and amine adsorption, which are likely different for different systems. Therefore, characterization of the effect of the triazine/H2S reaction processes on the surface properties of steel is an important factor that needs to be explored. In this paper, we seek to understand the effect of triazine on the electrochemical response of a carbon steel surface in a mixed gas system. Cyclic voltammetry was used to qualitatively assess the nature of the carbon steel surface with and without CO2 in the presence of triazine. Changes in surface film properties were also assessed using electrochemical impedance spectroscopy in an attempt to quantify changes in the electronic properties of the surface layer.
Corrosion of carbon steel in the presence of H2S is an important topic in the oil and gas industry that has been studied for more than fifty years. Recently, severe SCC has been observed in shale pipelines1. The exact mechanism has not been identified but several key factors are known. First, cracking is typically observed downstream of the H2S scavenger injection site. It is also known that for the relatively slow flow rates for shale gas pipelines, water hold up is more likely providing an initiation site for corrosion and cracking. Heavers1 suggests that the observed cracking was a form of amine cracking where the amines in the inhibitor increased pH over 8 which led to carbonate cracking. The primary basis for this assessment was that no Mackinawite or other FeS species were observed.