H2S Partial Pressure Research Articles

Nondispersive ultraviolet monitoring of pulsed H2S gas delivery

This article describes time-resolved optical measurements of H2S partial pressure and mass flow in a pulsed gas delivery system approximating injection conditions encountered during atomic layer deposition. A high-speed nondispersive ultraviolet (NDUV) gas analyzer design is employed for in-line H2S detection in a gas delivery line with flowing carrier gas. An in-place analyzer calibration performed in a reference cell yields an H2S detection limit of ≈1.4 Pa (at 22 °C) at a sampling rate of 1 kHz. Flow measurements performed on the delivery line are used to evaluate the effects of adjustable delivery parameters on the time-dependent injection system output. Short pulse widths exhibit partial pressure transients attributed to flow development within the different volumes of the delivery system. After ≈1.0 s of injection, steady-state flow is established across flow elements. A partial pressure of H2S in the delivery line is found to vary linearly with upstream H2S pressure, consistent with choked flow. A stronger scaling of partial pressure is evident when the flow coefficient of the downstream metering valve is adjusted. Estimated steady-state H2S flow rates in the range of 0.05–0.21 mg/s are observed within a limited range of valve flow coefficients. However, further increases in the flow coefficient do not result in increased flow, likely due to conductance limitations in downstream flow system components. The utility of NDUV absorption measurements for high-pressure pulsed gas delivery systems is discussed.

Effects of H2S content on the corrosion behavior of gas storage reservoir injection and production pipeline steel in CO2-H2S environment

The effects of H2S content on the corrosion behavior of gas storage reservoir injection and extraction pipeline steel in a CO2-H2S environment were investigated by surface characterization and ultrasonic thickness measurement. The results show that the corrosion products of gas injection and extraction pipelines under real conditions are more complex. In the CO2-H2S environment, with the increase of H2S content, the corrosion rate of gas storage reservoir gas injection and extraction pipeline steel firstly increases and then decreases. At a partial pressure ratio of CO2 to H2S of 550, corrosion resulted mainly in the formation of FeCO3, FeS2, and Fe3O4, with limited generation of stabilizing protective films. This led to severe localized corrosion, mainly driven by CO2. In contrast, when the CO2 to H2S partial pressure ratio was reduced to 5.2, the corrosion mainly produced Fe7S8, FeS2, and BaSO4, which promoted the formation of a more stable protective film on the inner wall of the tube, while the presence of gums reduced the severity of the localized corrosion and shifted the corrosion control to H2S.

Assessing sulfate-reducing bacteria influence on oilfield safety: Hydrogen sulfide emission and pipeline corrosion failure

With the further development of oilfield, excessive sulfate-reducing bacteria (SRB) has intensified odors and increased pipeline leakage incidents. Accurate predictive models of H2S emission and pipeline corrosion based on SRB content are essential for safety. This study analyzed the correlation between sulfide content and SRB content at different nodes in the injection-production system of Daqing Oilfield, and characterized the pipeline corrosion products using scanning electron microscopy (SEM), X-ray diffraction (XRD), and stereo microscope. Corrosion rates were investigated through 18 sets of orthogonal experiments, considering factors such as SRB, temperature, pH, liquid flow rate, CO2 partial pressure, and H2S partial pressure, and the main controlling factors of corrosion were identified. Finally, the risk models for H2S emission and corrosion rate based on SRB content were established under on-site operating conditions. The results show that a significantly positive correlated between SRB and sulfide content at different nodes, with the highest levels observed at the settling tank, indicating the highest risk of H2S emission. SRB contributed to corrosion in both water injection and oil collection pipelines, with more serious corrosion in the water injection pipeline. SRB and pH were identified as the main factors influencing corrosion rate. The H2S emission prediction model based on the correlation of SRB and sulfide was reliable, with an accuracy exceeding 90 % compared to the measured results. Additionally, the corrosion rate model for pipelines, related to SRB content, had an error of less than 7 %. To minimize risks, it is recommended to maintain a low risk environment in the injection-production system by sterilization and increasing the pH of water. This study has significant theoretical importance for ensuring the safe operation of injection-production systems.

Multi-factor corrosion model of TP110TS steel in H2S/CO2 coexistence and life prediction of petroleum casings

The failure of petroleum casings due to the combined effects of CO2/H2S corrosion and internal pressure has become a main concern during the exploitation of high-temperature, high-pressure, and high-corrosion gas fields. Therefore, establishing a corrosion evolution model is crucial for accurately predicting the service life of casings. In this study, an analytical model describing the corrosion rate of casing steel TP110TS under different CO2/H2S partial pressures and applied stresses was established, combined with the mechanical-chemical effect. The weightlessness method was used to determine the model parameters from the experimental results using a multiple regression. Based on the elasticity, a service life prediction model considering mechanical property attenuation and casing stress fluctuation was established from the assumption of uniform thickness thinning. The effects of internal pressure and CO2/H2S partial pressures on the service life were analyzed. The corrosion rate initially decreased with time. However, the stress increased as the wall thickness decreases from corrosion. The stress-promoting corrosion effect gradually manifested, and the corrosion rate rapidly increased. The higher the internal pressure and H2S/CO2 partial pressure, the shorter was the service life of the casing. In the H2S/CO2 coexistence environment, the influence of H2S partial pressure was more significant than that of CO2.

Corrosion of Zinc Cold Spray Coatings in a Wet Sweet and Sour Gas Environment

Internal corrosion is a problem for steel pipelines transporting natural gas or CO2 containing water and partial pressures of H2S higher than 0.3 kPa (0.05 psi). This work aims to mitigate internal corrosion in steel pipelines transporting natural gas containing H2S using cold spray coatings. Two types of the cold spray binary metallic coatings (zinc chromium [ZnCr]. zinc niobium [ZnNb]) were studied using electrochemical techniques: potentiodynamic polarization, linear polarization resistance, and electrochemical impedance spectroscopy. The corrosion resistance of cold spray coatings (ZnCr, ZnNb) was evaluated in an environment containing 4 bar CO2 pressure, simulating the partial pressures found in gas transmission lines over a solution of 3.5 wt% NaCl heated to 40°C. A concentration of 0.003 M Na2S2O3·5H2O, corresponding to H2S partial pressures around 0.079 bar (1.146 psi), was used to simulate sour conditions. Postcorrosion surface characterization was performed using a scanning electron microscope (SEM) equipped with an energy-dispersive x-ray spectroscope (EDS) and x-ray diffraction analysis. The data showed that the presence of 0.003 M Na2S2O3·5H2O shifted the corrosion potential to more anodic values and decreased the corrosion current density. Both coatings showed similar behavior after 1 h of exposure in the CO2/H2S environment, indicating that similar electrochemical reactions were occurring on ZnNb and ZnCr. SEM images and EDS surface analyses for specimens showed a significant change in the surface chemical composition of carbon steel coated with ZnNb and ZnCr after 24 h of immersion. In the presence of thiosulfate (under sour conditions), the formation of corrosion product layers (ZnCO3 and ZnS) on top of ZnNb and ZnCr coatings increased their corrosion resistance, which helped to reduce their corrosion by a factor of 2. Under a sweet environment, the corrosion rates for steel coated with cold spray coatings after 14 d of exposure are lower than that for galvanized steel by a factor of 5 due to the ZnCO3 layer formed on top of the coatings. The ZnCO3 layer formed on the steel surface acts as a physical barrier against corrosion by blocking the diffusion of corrosive species to the surface. No localized attack was observed. ZnCr Cold spray coating with defect showed promising corrosion protection against CO2 corrosion (sweet corrosion) after 14 d of exposure to a CO2 environment. The scratch on the coating simulated damage created in service, and it was deep enough to expose the substrate material (steel). The formation of zinc oxide (ZnO) and zinc carbonate (ZnCO3) on the scratch confirmed the cathodic protection of the steel by ZnCr and ZnNb coatings.

Highly efficient capture and removal of H2S by multi-amine functionalized ionic liquids

With the increasing awareness of environmental protection, H2S removal in natural gas has attracted more attention. In this study, three multi-amino functionalized ionic liquids (MFILs) were prepared with a one-step reaction. The solubility of H2S was measured at temperatures of 298.2 K to 328.2 K. Among them, diethylenetriamine imidazole ([DETAH][Im]) presented the unprecedented H2S solubility of 7.82 mol/kg (1.34 mol/mol) at 298.2 K and 0.1 bar H2S partial pressure, surpassing all the reported absorbent under the experimental condition. The H2S removal ability was determined with the interference of CO2, and the highest H2S removal efficiency reached 99.32% during four-hour absorption. The mechanism was elucidated by NMR, FT-IR, and DFT calculation. Moreover, five consecutive absorption–desorption cycles were performed to evaluate the regeneration efficiency. These MFILs represent apparent viscosity and absorption performance superiority over previously reported absorbents. These MFILs are a class of promising absorbents for sweetening natural gas.

New insight into the fitness of 13Cr stainless steel in H2S-containing environment at high temperature

In the oil and gas industry, the selection of tubing and casing materials is required to follow international standard ISO 15156. However, it does not provide guidance on selecting stainless steel materials for H2S-containing wells above 232 °C, which raises uncertainty about the suitability of 13Cr steel. This work focuses on investigating the mechanical degradation and failure mechanisms of 13Cr stainless steel exposed to high-temperature conditions and proposed a creep constitutive model. Then, the corrosion and cracking mechanisms of 13Cr stainless steel at temperatures ranging from 150 °C to 350 °C were elucidated. Results show that 13Cr stainless steel meets the current material selection criteria (GB/T34907-2017) for mechanical properties and creep resistance. In the range of 150–250 °C, the localized corrosion is dominant, and stress-oriented hydrogen-induced cracking occurs at 150 °C. As the temperature increases from 250 °C to 350 °C, although the maximum value of uniform corrosion rate is as high as 0.2960 mm/a, the cracking does not happen. Therefore, with the implementation of suitable protective measures, 13Cr stainless steel can be utilized in wells that the temperatures ranging from 250 °C to 350 °C and H2S partial pressures up to 0.17 MPa. This aligns with the global carbon-neutral agenda.

Molecular simulations of hybrid cross-linked membranes for H2S gas separation at very high temperatures and pressure: Binary 90%/10% N2/H2S and CH4/H2S, ternary 90%/9%/1% N2/CO2/H2S and CH4/CO2/H2S mixtures

Molecular dynamics (MD) simulations have previously identified four hybrid inorganic-organic membranes based on POSS or OAPS silsesquioxanes hyper-cross-linked with small PMDA or 6FDA imides, which are able to maintain reasonable CO2/N2 and CO2/CH4 permselectivities at very high temperatures (300 °C and 400 °C) and pressure (60 bar). Experimentally, the polyPOSS-imides are known to degrade above 300 °C while the polyOAPS-imides can resist up to above 400 °C. In the present work, the same four model polyOAPS/POSS-imide networks are further tested for their gas separation abilities of H2S-containing mixtures. Indeed, hydrogen sulfide is a hazardous gas present in many gas feeds, and, within the context of a toxic penetrant under harsh conditions, simulations are a useful task to perform before embarking on difficult experiments.The separations of H2S with respect to N2, CH4 and CO2 by the polyOAPS/POSS-imide matrices were studied at 300 °C, 400 °C and at 60 bar, firstly with H2S as a single-gas in order to obtain its ideal permselectivities, secondly as part of binary 90%/10% N2/H2S and CH4/H2S feeds and thirdly as part of ternary 90%/9%/1% N2/CO2/H2S and CH4/CO2/H2S feeds. They were compared to separations of binary 90%/10% N2/CO2 and CH4/CO2 feeds under exactly the same conditions.At 300 °C, H2S is much more soluble in the networks than the other three penetrants. It is the only one leading to a non-negligible volume swelling at 60 bar, although this does not happen for the mixed-gas feeds due to their low H2S partial pressures. Differences are attenuated at 400 °C because of the decrease in solubilities upon heating. The linear N2 and CO2 move faster than the non-linear CH4 and H2S penetrants, but the diffusion selectivities are moderate. As such, the ideal permselectivities under harsh conditions are mainly governed by the solubility selectivities. With binary 90%/10% N2/H2S, CH4/H2S, N2/CO2 and CH4/CO2 feeds, the transport parameters of the major N2 or CH4 components remain similar to their ideal values, whereas the solubilities of the minor H2S and CO2 components increase. This leads to some of the real separation factors for H2S being different from their ideal permselectivities, and approximately twice as high as those with CO2. In the ternary 90%/9%/1% N2/CO2/H2S and CH4/CO2/H2S mixtures, replacing 1% CO2 by 1% H2S in the feeds leads to small changes but, in pratice, these are not significant enough to make a difference. Under the conditions tested, the ternary separation factors are the same than for the 90%/10% binary mixtures.In all cases, the denser polyPOSS-imides show better sieving properties than the more open polyOAPS-imides. As such, the former should preferably be used in applications up to 300 °C, i.e. in the temperature range below their degradation. However, it is also possible to use the polyOAPS-imides at higher temperatures, since they still manage maintaining separation factors between 2 and 6 for CO2 and H2S at 400 °C, which is outstanding for polymer-based membranes at such high temperatures.

Corrosion law of cement paste under hydrogen sulfide conditions in natural gas wells

Downhole anticorrosion in sour gas (H2S or CO2) wells is one of the technical problems in petroleum engineering, and the corrosion law of cement paste, which is the “first barrier of the wellbore,” needs to be focused on. Aiming at the problems existing in the current research on the corrosion of underground cement paste, a curing method for interfacial corrosion is proposed. X-ray diffraction and scanning electron microscopy are used to investigate the corrosion mechanism of cement paste cured under hydrogen sulfide (H2S) conditions in natural gas wells. Experimental results showed that the corrosion depth of cement paste is proportional to the partial pressure of H2S and the corrosion time, and the compressive strength of cement paste after corrosion is inversely proportional to the H2S partial pressure value and the corrosion time. Due to the gradual enrichment, accumulation, and migration of products after the cement paste is corroded by H2S, the cement paste forms a relatively stable dense layer or corrosion transition zone. The porosity and permeability of cement paste after corrosion increased with corrosion time, showing the characteristics of first increasing and then decreasing and finally making it more difficult for the corrosive medium to enter the interior of the cement paste. It is an important method stable corrosion transition zone forms as soon as possible, which is important to maintain the long-term sealing and chemical integrity of the cement sheaths in natural gas wells containing H2S.

A Review of the Factors That Can Increase the Risk of Sulfide Stress Cracking in Thermomechanical Controlled Processed Pipeline Steels

This review aims to improve our understanding of the important factors which influence the susceptibility of thermomechanical controlled processed (TMCP) steels to sulfide stress cracking (SSC). Mechanisms involved in hydrogen embrittlement (HE) from three perspectives are focused on: the microstructure constituents of TMCP steels; environmental factors; and fracture mechanism of SSC. Microstructures are reviewed as they affect the diffusion and trapping of hydrogen that can reduce the resistance to fracture. Environmental factors discussed highlight that when exposed to an aqueous H2S environment, a sulfide layer can form and influence the ingress of hydrogen, and this is affected by pH, temperature, and H2S partial pressure. Fracture is influenced by the nature of the crack tip and the crack tip plastic zone during crack propagation, and hydrogen can significantly affect crack tip growth. This review provides a critical assessment of the interplay between these three factors and aims to provide understanding to enhance our engineering approaches to manage and mitigate against fracture of TMCP steels.

Evaluation of post weld heat treatments and susceptibility to sulfide stress corrosion cracking of simulated HAZ in forged supermartensitic stainless steel UNS S41427

Supermartensitic stainless steels (SSMSs) with 12–13%Cr, 5%Ni, 2%Mo and microadditions were developed to casings, tubullars and mandrels used in the oil and gas off-shore production. These materials have great resistance to aqueous medium containing large amounts of CO2 and can withstand high temperatures and large amounts of chloride as well. However, SMSSs have a limited resistance to H2S containing solutions, and may fail due to sulfide stress cracking (SSC). This limit is even lower for forged and welded components that used in mandrels. Recent studies have been developed to find an operational envelope for safe use of SMSSs in sour production systems. The present study shows the results of slow strain rate testing (SSRT) of a forged V-alloyed SMSS submited to thermal simulation in Gleeble machine to produce a coarse grain heat affected zone (HAZ). The microstructure of the HAZ is characterized by fresh martensite, intergranular delta ferrite and fine precipitates which increase the hardness to a level above the maximum limit for sulfide stress corrosion cracking. The effects of two post weld heat treatments (PWHT) on the mechanical properties and susceptibility SSC were evaluated. Single and double tempering treatments provoked the decrease of hardness and the increase of ductility parameters. However, specimens representative of the HAZ, base metal, and HAZ with single and double tempering presented high SSC susceptibility parameters in SSRT in saline solution (200,000 ppm NaCl) with 1.0 psia of H2S partial pressure, and pH 4.5.

Need for complementary techniques for reliable characterization of MoS2-like layers

The observation of characteristic A1g and E2g1 peaks, at around 408 and 382 cm−1, respectively, in Raman spectroscopy is considered the evidence of 2H-structured MoS2, probably the most extensively studied transition-metal dichalcogenide. Here, using a combination of x-ray diffraction, x-ray photoelectron spectroscopy, and resonant Raman spectroscopy, we show that the detection of A1g and E2g1 modes in Raman spectra alone may not necessarily imply the presence of MoS2. A series of Mo–S films, ≈ 20-nm-thick, are grown on single-crystalline Al2O3(0001) substrates at 1073 K as a function of H2S partial pressure, pH2S (= 0, 0.01%, 0.1%, and 1% of total pressure) via ultra-high vacuum dc magnetron sputtering of a Mo target in 20 m Torr (2.67 Pa) Ar/H2S gas mixtures. In pure Ar discharges and with pH2S up to 0.1%, i.e., pH2S ≤ 2.67 × 10−3 Pa, we obtain body centered cubic (bcc), 110-textured films with lattice parameter a increasing from 0.3148 nm (in pure Ar) to 0.3151 nm (at pH2S = 2.67 × 10−4 Pa), and 0.3170 nm (at pH2S = 2.67 × 10−3 Pa), which we attribute to increased incorporation of S in the Mo lattice. With 1% H2S, i.e., pH2S = 2.67 × 10−2 Pa, we obtain 000l oriented 2H-structured MoS2.0±0.1 layers. Raman spectra of the thin films grown using 0.1% (and 1%) H2S show peaks at around 412 (408) and 380 cm−1 (382 cm−1), which could be interpreted as A1g and E2g1 Raman modes for 2H-MoS2. By comparing the Raman spectra of MoS2.0±0.1 and Mo:S thin films, we identify differences in A1g and E2g1 peak positions and intensities of defect-sensitive peaks relative to the A1g peaks that can help distinguish pure MoS2 from non-stoichiometric MoS2−x and multiphase Mo:S materials.

Optimizing Sour Gas Qualification Testing—Modeling the Effects of Temperature and Total Pressure on H2S Fugacity, Activity, and Solubility Coefficients up to 138 MPa and 204°C

Traditionally, the sour severities of high-pressure high-temperature (HPHT) oil and gas production wells were assessed by H2S partial pressure (PH2S): The mole fraction of H2S in the gas (yH2S) multiplied by the total pressure (PT). However, PH2S usually over-predicts the actual sour severity of HPHT systems, leading to suboptimal material selection choices. To reflect recent advances in thermodynamic modeling and to avoid over-conservatism, after careful deliberation, ANSI/NACE MR0175-2021/ISO 15156-2:2022 recently expanded the number of sour severity metrics to four: PH2S, fugacity (fH2S), chemical activity (aH2S), and dissolved concentration (CH2S) of the aqueous phase. The new metrics are often computationally derived and account for thermodynamic nonidealities, which are significant at HPHT conditions. Regardless of the preferred metric, quantifying the sensitivity of each metric to a wide range of temperatures and total pressures is critical when conducting H2S service assessments. In this article, the effect of increasing temperature and total pressure on the thermodynamically derived apparent H2S solubility (KH2S = CH2S/PH2S) was investigated. KH2S is a critical parameter for quantifying changes in H2S phase behavior/sour severity of HPHT systems. Apparent KH2S values were calculated by two different thermodynamic models and benchmarked to two publicly available H2S/H2O datasets up to 120°C and 10.3 MPa equilibrated in a brine containing 165,000 mg/L Cl−. The model that provided the best match to the experimental data was later used in a much broader thermodynamic sensitivity study of the H2S/CH4/H2O/NaCl “oilfield” system. For this sensitivity analysis, changes in fH2S, aH2S, CH2S, and KH2S were individually modeled between 4°C and 204°C, at total pressures up to 138 MPa, and in brines containing up to 25 wt% NaCl (180,000 mg/L Cl−). Lastly, a comparison of the predicted sour severity by pseudo-PH2S, fH2S, and CH2S metrics, over the same temperature and total pressure parameter space, is presented.

The synergistic effect of temperature, H2S/CO2 partial pressure and stress toward corrosion of X80 pipeline steel

In this work, the H2S / CO2 coexistence environment was simulated in a high-temperature and high-pressure reactor. The influence of H2S/CO2 partial pressure (0/1.2, 0.7/1.2 and 2.0/1.2 MPa), temperature (50, 100 and 150 °C) and applied stress (30%, 70% and 90% σs) on the corrosion rates of natural gas pipeline steel X80 was investigated by the weight loss measurements combined with the SEM, EDS and XRD techniques. The results show that the corrosion of X80 steel under pure CO2 condition is much more serious than that under H2S/CO2 coexistence. The corrosion stability of amorphous film can be improved by the formation of amorphous Cr (OH)3 in the presence of H2S, which provides better surface protection than in the pure CO2 environment. The corrosion of X80 steel in H2S/CO2 coexistence is dominated by H2S corrosion and the corrosion rates increase with the increase of H2S partial pressure. The corrosion rate firstly increases with the increase of temperature, and the highest corrosion rate occurs near 100 °C under the existing experimental conditions. After that, the corrosion rate began to decrease. The applied stress significantly affects the corrosion rate, and high stress speeds up the corrosion process of X80 steel in the H2S/CO2 coexistence environment.

Corrosion Study of 80S Steel under the Coexistence of CO2 and H2S

The continuous rise in the energy demand has shifted the extraction environment in oil and gas fields towards a more hostile environment, and has ultimately increased the corrosion of extraction and transmission facilities. One of the most effective solutions for mitigating the corrosion problem is the use of corrosion-resistant metals. In this paper, we investigated the corrosion behavior of 80S steel that was being employed in an oilfield underground gathering pipeline at different temperatures and partial pressures of H2S and CO2 using an autoclave. Moreover, the loss-in-weight method was used to simulate the corrosive environment in the oilfield. Electrochemical studies were then carried out to investigate the corrosion mechanism. The results show that: (1) In the corrosive environment of CO2 and H2S coexistence, temperature is a major factor affecting the corrosion rate of 80S steel, and increase in temperature accelerates the corrosion process. (2) Corrosion rate is also affected by the CO2 and H2S partial pressure ratio; high S content at high temperatures will inhibit the corrosion process, and vice versa for low temperature. (3) With an increase in the temperature, the corrosion potential decreases, corrosion current density increases, and polarization curve gradually moves to the right. (4) The shape of the cathodic branch moves in the X-negative direction by increasing S content, and the cathodic reaction is jointly controlled by activation and diffusion processes, when the temperature is 100 °C, whereas the anodic branch of the polarization curve at a 3% concentration of Na2S.9H2O changes significantly and a passivation zone appears. (5) The results of the impedance spectra showed that the impedance radius of the metal decreases significantly at increasing temperatures. In addition, the Warburg impedance showed a more pronounced diffusion phenomenon with the increasement of H2S concentration.

Quasi-epitaxial growth of BaTiS3 films

Perovskite chalcogenides have emerged as a new class of semiconductors with tunable band gap in the visible-infrared region. High quality thin films are critical to understand the fundamental properties and realize the potential applications based on these materials. We report growth of quasi-epitaxial thin films of quasi one-dimensional (quasi-1D) hexagonal chalcogenide BaTiS$_3$ by pulsed laser deposition. We identified the optimal growth conditions by varying the growth parameters such as the substrate temperature and H2S partial pressure and examined their effects on the thin film structure. High resolution thin film X-Ray diffraction shows strong texture in the out-of-plane direction, whereas no evidence of in-plane relationship between the film and the substrate is observed. Grazing incidence wide-angle X-ray scattering and scanning transmission electron microscopy studies reveal the presence of weak epitaxial relationships of the film and the substrate, despite a defective interface. Our study opens up a pathway to realize quasi-1D hexagonal chalcogenide thin films and their heterostructures with perovskite chalcogenides.

In Situ Investigation of Hydrogen-Induced Cracking Behavior in Linepipe Steel Under Different Environments

NACE MR0175/ISO 15156 provides the severity of a sour environment defined as a function of pH and H2S partial pressure for sulfide stress cracking. Although hydrogen-induced cracking (HIC) is also a major issue of linepipes exposed to a sour environment, the severity diagram does not necessarily correspond to the HIC susceptibility. Recently, from the viewpoint of fitness-of-purpose, the severity diagrams for HIC have been proposed based on the concept of equal hydrogen concentration. From this concept, HIC susceptibility corresponds well to the steady-state hydrogen permeability obtained from the hydrogen permeation test method. In this study, in order to clarify the relationship between HIC susceptibility and hydrogen diffusion behavior, in situ crack inspection during the HIC test and finite element method analysis of hydrogen diffusion were performed. The in situ inspection technique using phased-array ultrasonic testing which can capture the time dependence of crack distribution, and HIC initiation and propagation behaviors were clearly visualized and investigated. It was found that crack initiation and propagation stabilize as hydrogen concentration reaches a steady-state value throughout the specimen and the result was considered evidence that the HIC susceptibility corresponded with the steady value of hydrogen permeability.

Corrosion main control factors and corrosion degree prediction charts in H2S and CO2 coexisting associated gas pipelines

The pipeline corrosive environment in T oil field contains H2S and CO2, with 96 corrosion perforations. OLGA software was used to simulate the internal flow environment. Combined with Pearson correlation coefficient analysis method and the Apriori algorithm, the association rules between corrosion rate and main corrosion control factors were determined. The results show that corrosion perforation of associated gas pipelines mostly occurred at the effusion in low-lying and climbing sections. Corrosion in the associated gas pipelines were strongly related to liquid velocity and holdup, and moderately related to temperature, H2S partial pressure and CO2 partial pressure. 10 association rules with confidence ≥90% between main corrosion control factors and corrosion rate were mined. Finally, the three kinds of corrosion evaluation charts parameters: liquid velocity & holdup, temperature & PCO2/PH2S and liquid velocity & PCO2/PH2S were established respectively.

Coiled Tubing Program Succeeds in Harsh-Environment Tight Gas Wells

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 209032, “Successfully Adapting and Overcoming Challenges for Coiled Tubing Applications in High-Pressure Sour Environments and Horizontal Unconventional Tight Gas Wells in UAE,” by Ole Sorensen, Yang Wu, and Didier Caillon, SPE, TotalEnergies, et al. The paper has not been peer reviewed. During the completion phase of four unconventional wells in the United Arab Emirates, a detailed engineering approach overcame challenges presented by extreme conditions of pressure, temperature, and a sour environment across long horizontal sections to carry out cleanout activities successfully. This operation, the first of its kind in the country for the operator, yielded lessons for design considerations and the execution process and recommendations for coiled tubing (CT) intervention in similar working environments. It also confirmed that 110,000-psi-yield-strength quench-and-tempered (Q&T) CT strings can be deployed safely in a high-pressure sour environment by implementing proper risk-mitigation strategies. Introduction The unconventional gas play (referred to as “A” in the complete paper) featured a reservoir pressure of nearly 13,000 psi and a bottomhole temperature of approximately 325°F. The environment was sour, with 5 mol% of hydrogen sulfide (H2S) and 5% carbon dioxide (CO2). The well’s architecture consisted of a 5½-in. monobore completion with cemented casing and horizontal sections ranging from 5,000 to 8,200 ft. The selected completion methodology was plug-and-perf, including up to 35 fracturing stages in a single well. Overview of CT Intervention Challenges The true vertical depth of the play was 12,600 ft on average, representing a maximum anticipated surface pressure (MASP) of 8,000 psi with the wellbore full of working fluid (8.34-lbm/gal slickwater) and a maximum potential wellhead pressure (MPWHP) of 11,300 psi with the wellbore full of gas. Also, partial pressures of H2S and CO2 exceeded 600 psi at bottomhole conditions, confirming that sour- and corrosive-service programs had to be implemented fully in this project. Convergence of MASP above 7,500 psi, CT dynamic pressure of greater than 11,000 psi, lateral length of up to 8,200 ft, and the sour and corrosive environment required a highly engineered approach on the design and selection of the CT string and configuration of the surface equipment.

Development of the NACE “MR-01-75” and NACE “TM-01-77” Standards, Part II: Accelerated Material Qualification Testing in Sour Environments at Near Atmospheric Pressure

This paper is Part II of a two-part series intended to narrate the history, some of which has been forgotten over time, leading up to the publication of the first Material Requirement (MR-01-75) standard prepared by NACE and its subsequent auxiliary standards. Previously, Part I described the field observations and discussed the metallurgical factors that were being investigated by the historical NACE T-1B and 1F committees to support the development of a sour service materials standard. In Part II, we focus on the rationale behind the use of accelerated laboratory test procedures designed to differentiate metallurgical behavior in sour environments. The original sulfide stress cracking test methodologies would later be codified as a Test Method in NACE TM-01-77 (1977). A review of the historical events culminating in NACE MR-01-75 and NACE TM-01-77 provides a technical basis for the historical use of NACE solution A (5 wt% NaCl + 0.5 wt% acetic acid) to evaluate metallurgical factors, and the origins of several common SSC NACE Test Methods still used today: Methods A (tensile), B (three-point bent beam), and C (C-ring). The accelerated laboratory test results, in combination with parallel field trials (performed in advance of the first NACE MR-01-75 publication), supported the ≤22 Rockwell C (22 HRC) hardness limit for carbon and low alloy steels in sour environments containing ≥0.05 psia H2S partial pressure. As the oil and gas industry continues to innovate and mature, it was imperative to maintain knowledge of the origins of the NACE MR-01-75 and TM-01-77 standards and their intended purposes.