Sour Service Research Articles

Effect of Microstructure on Mechanical Properties of X65MS Welded Pipe Joint

The mechanical properties of welded joints have a crucial impact on the safety of pipelines. This article focuses on examining the correlation between the microstructure and mechanical properties of welded joints of X65MS pipeline steel for sour service. The results indicate that the welding thermal cycle forms the microstructure consisting of acicular ferrite, granular bainite, and polygonal ferrite. The hardness across the joint ranges from 210 and 270 HV, peaking within the welded zone and decreasing towards the base metal (BM). At −40 °C, the welded zone shows the lowest impact energy of 53 J, while heat‐affected zones exhibit superior impact toughness exceeding 270 J with the highest impact energy of 326 J. This can be attributed to the exceptionally fine‐grained microstructure, a small quantity of small‐sized martensite‐austenite (M/A) constituents in the heat affected zone. As for the low toughness of the weld, the main factors can be attributed to the presence of large‐sized elongated M/A constituents and inclusions.

Experimental and computational failure analysis of hydrogen embrittled steel cords in a reinforced thermoplastic composite pipe

Reinforced thermoplastic pipes (RTPs) have attracted considerable attention lately in the oil and gas sector as potential alternative to carbon steel pipes. However, some RTP systems have been experiencing failures as a result of deficient design and inadequate operation practices. This study presents a comprehensive assessment of the failure of a steel-reinforced flexible thermoplastic composite layered pipe in a sour environment characterized by hydrogen sulfide (H2S) exposure. Utilizing scanning electron microscopy (SEM) and electron dispersive spectroscopy (EDS), the investigation conclusively attributes the failure of the RTP to hydrogen embrittlement of the carbon steel cords and wires in the reinforcement layer. Finite element models at both meso-scale and full RTP scale were developed, incorporating a novel damage initiation and propagation criterion for failure prediction of embrittled and non-embrittled (e.g. ductile) reinforcement steel cords. The numerical models consistently predicted a reduced burst pressures of the hydrogen embrittled case of the RTP, with a close match with field observations. They also predicted failure modes that closely matched the SEM findings, hence highlighting the unsuitability of the existing steel cords in RTPs for use in sour service environments. Additionally, the presence of moisture in the annular space was identified as an exacerbating factor. This investigation provides important insights for the future design and operation of RTPs susceptible to hydrogen embrittlement, paving the way for improved structural integrity and safety measures. Further research avenues may involve modeling hydrogen diffusion in the thermoplastic layers, simulating the movement of moisture in the annulus through the capillary effect, and incorporating fracture toughness degradation for a more thorough understanding of the interplay between mechanical and environmental factors in the hydrogen embrittlement of steel-reinforced RTP composite pipes.

Predicting sulfide stress cracking in a sour environment: A phase-field finite element study

Sulfide stress cracking (SSC) is a leading cause of failure in sour service environments, where the presence of wet hydrogen sulfide (H2S) causes hydrogen embrittlement and significantly influences the performance and lifespan of casing and tubing pipes. This work presents a numerical investigation on predicting the onset and growth of SSC in a sour environment using a coupled deformation–diffusion phase-field finite element framework, which incorporates the role of sub-surface hydrogen concentration due to H2S exposure and mechanical loading effects on the crack growth response. The numerical results agree with the experimental data from the notched slow strain rate testing performed on high-strength low alloy steel (HSLA) in a sour environment at room temperature. Recently, the oil and gas industry has been heading towards unconventional gas well applications that expose crucial parts of a well construction, such as production casings, to high internal pressures and a sour environment. To simulate such conditions, a numerical study is conducted that examines the onset and growth of SSC in pre-notched pressurized pipes subjected to H2S exposure. The geometry and boundary conditions used for the pre-notched pipes adhere to the API 579 standard for fitness for a service assessment of equipment containing identified flaws or damage. The findings of this comprehensive numerical investigation provide valuable insights into the effectiveness of a coupled phase-field approach for SSC and demonstrate its potential as an engineering tool for structural integrity assessments that consider environmental effects.

Sulfide Stress Cracking of column overhead pipe to flange fitting joints in a petroleum industry

The light hydrocarbon containment leakage in a petroleum industry overhead piping have caused severe fire explosion. This paper reports Sulfide Stress Cracking (SSC) in an overhead piping of splitter unit which separates out lighter components from heavier hydrocarbon. The failed overhead piping has been analyzed to determine the root cause of fire incident. The piping metallurgy was SS316L and chemistry of failed fitting components & its weld have been complied with NACE specification. Initially fittings were evaluated for intergranular corrosion to determine as-received material condition and confirmed defect free material. However, metallographic evaluation clearly evidenced transgranular brittle mode of cracking while hardness was higher than NACE specification (22HRC). Furthermore, virgin pipe joint was compared with damaged pipe joint for microstructural assessment. Moreover, actual service conditions were evaluated to obtain pH and H2S concentration in overhead condensed boot water. Microstructural factors have been discussed in detail as well. The results revealed that cold deformed austenitic structure attributed to SSC and undesired manufacturing steps were employed. Further, the root cause of an accident investigation also revealed failed components were not according to NACE specified metallurgy for sour service conditions.

Hydrogen charging of carbon and low alloy steel by electrochemical methods

Atomic hydrogen can be the result of different processes like electroplating, chemical and electrochemical pickling treatments, in welding or by cathodic processes in corrosive fluids. Moreover, adsorption of atomic hydrogen can affect materials in contact with high pressure gaseous hydrogen. Once entered the material, atomic hydrogen interacts with the metal structure and may produce a “damage” of various forms, such as Hydrogen Induced Cracking (HIC), delayed fracture, blistering and hydrogen embrittlement. In particular, when H2S is present (“sour service”), metallic materials, such as carbon and low alloy steels, may suffer hydrogen damage and hydrogen embrittlement. Sour service materials must be used in compliance with international accepted standards, used worldwide in oil and gas activities, when fluids are classified as sour. The present study has been carried out in order to set up an electrochemical method to charge with hydrogen two typical pipeline materials, carbon and low alloy steels. The reason of the use of an electrochemical method is to avoid any critical conditions from the point of view of preparation, safety and disposal. Hydrogen content in the specimens was measured by two different methods: hot glycerol bath and Inert Gas Fusion (IGF) analysis. Hydrogen content in the specimens is about 0.6–2 ppm; mechanical performances were assessed by means of J integral tests: a pronounced decrease of fracture toughness was observed for H charged specimens.Graphical

TUBING HANGER INVESTIGATION OF LOADING

In this article, the failures of tube hangers made from UNS N07718 are discussed. An arrangement known as a tubing hanger may be found in wells that produce either oil or gas. It is positioned in the upper tubing head’s bowl after it has been installed. The tubing is held in place by this, and a main annulus seal is created between tubing also the production casing. This holds the tubing in place, and at the same time, it creates a primary annulus seal between tubing also production casing. When compared to odd component in wellhead system, tubing hangers are available in a broader range of styles and sizes than any other option. Tubing hangers made of UNS N07718 are often used in the installation process of sour service oil and gas wells that operate under high pressure and also high temperatures. Afterwards more than 10 years of service, it was only recently found that the tubing hanger made of UNS N07718 had failed in sour wells. Failures of the tubing hanger will inference in substantial production delays as well as high workover expenses. The purpose of this research is to demonstrate the failure mechanism of tubing hanger furthermore its ramifications on existing wells that were erected with material that is comparable to what was used here. In order to establish what caused the failure, each and every exposure that was brought on by well intervention efforts was evaluated. The manner of failure of stringer head suspension was researched, as was its influence on already existing wells that had been erected with materials that were comparable. Keywords: tubing head, tubing hanger, tubing thread, back pressure valve profile, landing shoulder, snap ring, running thread,

A Three-stage Hybrid Multi-criteria Model for the Selection of Material for Subsea Pipeline Design Considering Several Environmental Scenario.

Subsea pipelines are such a crucial part of offshore oil and gas production, therefore their design and construction should be as efficient and cost effective as possible. Proper material selection is critical for a successful operation and a longer pipeline lifespan. For the selection of a design material with the highest reliability under dynamic environment as the one obtained in the oil and gas industry, a three-stage hybrid multi-criteria model have been proposed. The hybrid multi-criteria model, which is based on an integrated Analytical Hierarchy Process (AHP) model and the VlseKriterijumskaOptimizacija I KompromisnoResenje (VIKOR) model, is used for the evaluation and selection of a suitable and high reliability-based design material for the subsea pipeline design by considering several operational and environmental scenario the pipes might encounter in the field. With the vast amount of engineering materials available to the design engineer, selecting a suitable and high reliability-based material for the subsea pipeline design is a tedious and demanding task especially under a dynamic environment scenario. In this paper, ten subsea pipeline material alternatives of different types, with seven criteria, have been critically examined under a three case scenario. Results from the evaluation show that, for the first case study scenario -sour service hydrocarbon transport in deep waters-, 22% Cr stainless steel is found to be the best choice material, for the second case study scenario, Carbon Fiber Reinforced Polymer is selected as the best. While for the third case study scenario, carbons steel and polymers material is found to be the most reliable material choice.

Weldability evaluation of X80 sour line pipe using a combination of thermal simulation and actual girth welding

The weldability studies of API 5LX80 pipes developed for sour service are very recent and limited information about its heat-affected zone (HAZ) properties can be found. This paper presents a comprehensive evaluation of HAZ using both thermal simulation and the production of actual girth weld joints. The test methodology included microstructural analysis, Charpy impact test, hardness (HV10), microhardness (HV0.1), and sulfide stress cracking tests (SCC). The intercritical coarse grain HAZ presented impact toughness reduction from values above 300 J to less than 50 J at 0 °C when heat input is increased above 1.5 kJ/mm. It can be explained by grain coarsening and martensite-austenite (MA) formation as a ‘necklace’ structure at previous austenite grain boundaries. Hardness and microhardness values for both simulated and actual HAZ were below the maximum limit of 250HV usually specified by industry. Specimens submitted to the sulfide stress cracking (SSC) tests did not present any crack demonstrating that the welded joint is appropriate for sour environments. Finally, a maximum heat input of 1.5 kJ/mm is recommended for field welding. For higher heat inputs, a deeper evaluation of HAZ toughness should be done. The results contribute to supporting the application of this material as an alternative for long-distance high-pressure pipelines with H2S.

Hardening mechanisms in a high wall thickness sour service pipe steel API 5L X65 before and after post-welding heat treatments

The strength of the pipe region opposite to the weld in a high wall thickness sour service pipeline steel API 5L X65, manufactured by the SAW UOE process, has been studied in detail. The fundamental hardening mechanisms that contribute to the yield strength of this pipe portion were determined according to its microstructural features before and after post-weld stress relieving heat treatment. The root mean square summation of the different strengthening mechanisms resulted in a reasonable estimate of the yield strength of this pipe portion before the heat treatment. The contributions of the different strengthening mechanisms proceeded at different length scales in this pipe portion before and after the heat treatment. The heat treatment at 650 °C (1.5 h) reduced the contributions of the strengthening mechanisms to the steel yield strength corresponding to this pipe portion. The dislocation strengthening contribution decreased by approximately 50%. The precipitation hardening and the solid solution and grain size strengthening reduced their contributions by approximately 14% and 3% respectively.

Investigations of Welding Parameters Impacts on Mechanical & Corrosion Behavior of Steel Welds

Now days while the welded product of duplex stainless steels (DSS) is to be used for Cl- containing environment & sour service applications for example petrochemical, off-shore platforms, oil, gas, paper & pulp industries etc. The resistance to chloride stress corrosion cracking (CSCC) during service application has always been a threat for the manufacturer & the end user of the product. Resistance regards SCC under chloride existing environment based on current ferrite content under carefully welded duplex (ferrite-austenitic) stainless steel framework. DSS ferrite specifications required by various organizations are 30 to 60%, 30 to 70 Ferrite Number, 35 to 75%, etc. In this study, DSS 2205 material all weld metal consumable test coupons within ferrite content range 14% to 30% or 20 FN to 40 FN have been prepared & investigated. Investigations have shown that yield strength & tensile strength needs regards base metal & filler metal classifications was higher at every ferrite levels observations & no SCC cracking analysed after 1000 hours exposure at ferrite level below 15%.

INTEGRATED COMPLETION STUDY FOR HPHT SOUR GAS WELL DEVELOPMENT IN CARBONATE RESERVOIR X

Recently, Indonesia will lead to gas deficits since the increase in domestic gas demand in 2040. The increasing need for energy sources and the decreasing available reserves have encouraged oil and gas companies to explore and manage marginal reservoirs such as sour gas environment to maintain the balance of energy supply and demand. The gap in gas supply-demand will decrease by 20% due to the supply of Natuna Gas Field, as the example of potential sour gas environment (Batubara, 2015). Thus, it is very relevant to develop this potential source immediately.
 Also, sour gas field approximately shares 40% of Indonesia’s total proven gas reserve with an estimated OGIP of around 222 TSCF, with 75% of gas recovery. Unfortunately, sour gas environment cannot be produced economically since the it has high carbon dioxide (CO2) and hydrogen sulfide (H2S) content, which are toxic and corrosive.
 The X sour reserves contain 32% carbon dioxide (CO2) and 7072 ppm H2S with fluid gravity of 42 API. This discretionary source of CO2 was recently brought into production from one well with depth of 8400 ft. The well was perforated in a limited interval of 7100 until 7700 ft. The harsh environment presented many challenges to completion design. Unique equipment and material selection were required.
 This study aims to determine the reservoir fluids and production performance also predict the corrosivity of CO2 dissolved in the natural gas. With the simulation and prediction, it can be obtained the proper material and equipment selection based on the sour service needed. As a result, the wet gas reservoir of X field can produce optimum rate of 19.1063 MMSCFD. For completion design, Nickel Alloy SM2535 or SM2242 is needed as there will be damage in form of corrosion and pitting.

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.

Development of the NACE MR-01-75 and NACE TM-01-77 Standards, Part I: Field Observations and Metallurgical Factors

This is Part I of a two-part series intended to narrate the “lost” history leading up to the publication of the first Material Requirement (MR-01-75) standard prepared by NACE (now AMPP) and its subsequent auxiliary standards. Part I covers field observations and describe the metallurgical issues that were being investigated in support of NACE T-1B and 1F committees to develop a sour service materials standard for carbon and low alloy steels. Part II focuses on the rationale behind the use of accelerated laboratory test procedures and their development to differentiate metallurgical behavior in sour environments at near atmospheric pressure. 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 will provide a technical basis for the Rockwell C 22 (HRC 22) hardness limit, information on the 1% Ni restriction, and heat-treatment requirements for carbon and low alloy steels. By recalling the origins of the MR-01-75 standard, these papers will also provide justification for their continued existence when designing modern, oil and gas wells and flowlines. As the oil and gas industry continues to innovate and mature, it is imperative to maintain knowledge of the origins of the NACE MR-01-75 standard and its intended purpose.

Corrosion characterization of new low manganese microalloyed X65 steels in sour and NON-SOUR synthetic seawater

API 5L X65 microalloyed steels are extensively used for oil and gas transportation. In many cases, reserves of such resources contain H2S, constituting what is called a sour medium, at which hydrogen-induced failures are critical. Even though essential for improving mechanical resistance, the addition of high contents of manganese (Mn) may increase the tendency for segregation and the precipitation of MnS inclusions, increasing the susceptibility to hydrogen-induced failures. In this study, electrochemical techniques were employed to compare the corrosion resistance in the B solution of ASTM D1141−98 (synthetic seawater) of three API 5L X65 microalloyed steels with low Mn content, designed for severe sour service applications. Experiments were performed in naturally aerated (pH 8.0), deaerated (pH 8.0 and 5.0), and H2S-saturated (sour pH 5.0) media. Although the steels exhibit very similar chemical compositions and mechanical properties, it was possible to rank their corrosion resistance. Microstructural characterization allowed associating corrosion susceptibility with the presence of pearlite grains in a ferritic matrix. The results also demonstrated the superior aggressiveness of the sour medium, and that the precipitation of a poorly adherent layer of Mackinawite slightly increases the corrosion resistance with immersion time.

Hydrogen Stress Cracking Resistance and Hydrogen Transport Properties of ASTM A508 Grade 4N

Low alloy steels combine relatively low cost with exceptional mechanical properties, making them commonplace in oil and gas equipment. However, their strength and hardness are restricted for sour environments to prevent different forms of hydrogen embrittlement. Materials used in sour services are regulated by the ISO 15156-2 standard, which imposes a maximum hardness of 250 HV (22 HRC) and allows up to 1.0 wt% Ni additions due to hydrogen embrittlement concerns. Low alloy steels that exceed the ISO 15156-2 limit have to be qualified for service, lowering their commercial appeal. As a result, high-performing, usually high-nickel, low alloy steels used successfully in other industries are rarely considered for sour service. In this work, the hydrogen stress cracking resistance of the high-nickel (3.41 wt%), quenched and tempered, nuclear-grade ASTM A508 Gr.4N low alloy steel was investigated using slow strain rate testing as a function of applied cathodic potential. Results showed that the yield strength and ultimate tensile strength were unaffected by hydrogen, even at a high negative potential of −2.00 VAg/AgCl. Hydrogen embrittlement effects were observed once the material started necking, manifested by a loss in ductility with increasing applied cathodic potentials. Indeed, A508 Gr.4N was less affected by hydrogen at high cathodic potentials than a low-strength (yield strength = 340 MPa) ferritic-pearlitic low alloy steel of similar nickel content. Additionally, hydrogen diffusivity was measured using the hydrogen permeation test. The calculated hydrogen diffusion coefficient of the ASTM A508 Gr.4N was two orders of magnitude smaller when compared to that of ferritic-pearlitic steels. Hydrogen embrittlement and diffusion results were linked to the microstructure features. The microstructure consisted of a bainitic/martensitic matrix with the presence of Cr23C6 carbides as well as Mo- and V-rich precipitates, which might have played a role in retarding hydrogen diffusion, kept responsible for the improved HE resistance.

Well Integrity Study for CO_2 WAG Application in Mature Field X, South Sumatra Area for the Fulfillment as CO2 Sequestration Sink

The most of today's global oil production comes from mature fields. Oil companies and governments are both concerned about increasing oil recovery from aging resources. To maintain oil production, the mature field must apply the Enhanced Oil Recovery method. water-alternating-gas (WAG) injection is an enhanced oil recovery method designed to improve sweep efficiency during injection with the injected water to control the mobility of . This study will discuss possible corrosion during and water injection and the casing load calculation along with the production tubing during the injection phase. The following study also performed a suitable material selection for the best performance injection. This research was conducted by evaluating casing integrity for simulate water-alternating-gas (WAG) to be applied in the X-well in the Y-field, South Sumatra, Indonesia. Corrosion prediction were performed using Electronic Corrosion Engineer (ECE®) corrosion model and for the strength of tubing which included burst, collapse, and tension of production casing was assessed using Microsoft Excel. This study concluded that for the casing load calculation results in 600 psi of burst pressure, collapse pressure of 2,555.64 psi, and tension of 190,528 lbf. All of these results are still following the K-55 production casing rating. While injecting , the maximum corrosion rate occurs. It has a maximum corrosion rate of 2.02 mm/year and a minimum corrosion rate of 0.36 mm/year. With this value, it is above NORSOK Standard M-001 which is 2 mm/year and needs to be evaluated to prevent the rate to remain stable and not decrease in the following years. To prevent the effect of maximum corrosion rate, the casing material must use a SM13CR (Martensitic Stainless Steel) which is not sour service material.

Improved High-Pressure, High-Temperature (HPHT) Materials Qualification Using Dissolved H2S Concentration as the Sour Service Scalable Metric

Gas phase H2S partial pressure (PH2S) is associated with sulfide stress cracking (SSC) and is routinely used as the “scalable” parameter to qualify materials for high-pressure, high-temperature (HPHT) wells. Candidate materials for HPHT wells routinely require ANSI/NACE MR0175/ISO 15156 compliance because a few mole ppm of H2S at high pressure may place the well beyond the 0.05 psia (0.3 kPa) sour service threshold. PH2S has been accepted historically as the scalable sour severity parameter. However, as the total pressure increases, the relationship between PH2S and the dissolved H2S concentration becomes nonlinear. This limits the robustness of PH2S as the sour severity metric. Thus, ISO 15156-1:2020 now permits the use of H2S fugacity (fH2S), H2S activity (aH2S), and H2S aqueous concentration (CH2S) as alternatives for sour testing. This recent revision is based on evidence that fH2S and CH2S each provide better correlations to SSC at elevated total pressures than PH2S. This paper will address the merits and challenges of using fH2S or CH2S to define sour severity: we argue that CH2S is a practical, experimentally verifiable approach, which can be used to validate ionic-equation of state frameworks used to characterize mildly sour HPHT environments.

Microstructural and crystallographic characterization of 455 MPa sour service plates with low Mn high temperature processed alloy concept and its association with drop weight tear test performance

The aim of this study was to analyze the mechanical properties of a X65 low Mn and high Nb steel for sour service application, particularly the drop-weight-tear test (DWTT) performance in order to establish correlation with the microstructural and crystallographic features of a steel with complex microstructure. Samples were analyzed at 55%, 65% and 75% of deformation during the finishing stage of rolling. The characterization of the samples involved electron backscatter diffraction (EBSD) technique for the determination and volume fraction quantification of the microconstituents and crystallographic texture analyses. The results showed that the plate with 55% of deformation displayed the lowest level of strength and the lowest DWTT shear area, while the plate with 65% of deformation exhibited the highest strength and DWTT toughness levels. EBSD results indicated that the plate produced with 65% of deformation had the largest dislocation density among all three samples and showed the highest intensity of the texture components concentrated along the α-fiber, particularly in the vicinity of the {113}<110> and {112}<110> components, responsible for activating ductile fracture, while samples 55% and 75% had a broader spread towards {001}<110>, and an overall higher intensity of the rotated cube components that favor cleavage fracture. For the plate with 75% of deformation, the mean flow stress (MFS) result suggested that partial recrystallization occurred during the finishing stage of hot rolling which was also proved by EBSD.These findings have proven that low Mn steels processed at high temperatures have a crucial dependency on Nb for the development of deformation textures that will help sustain high levels of fracture toughness, particularly when dealing with heavy plates for offshore applications. It has been observed that this steel concept is inclined to experience loss of toughness due to the softening of austenite during the finishing stage of rolling, even though the temperatures were below the no-recrystallization temperature, and a proper rolling schedule must be selected to mitigate this effect.The overall results showed that a rolling scheduled aiming at increasing the volume fraction of acicular ferrite and reducing the polygonal ferrite together with a higher level of strain and crystallographic texture consisting of high intensity deformation components, will result in a better combination of strength and toughness.

Well Integrity Study for CO2 WAG Application in Mature Field X, South Sumatra Area for the Fulfillment as CO2 Sequestration Sink

The most of today's global oil production comes from mature fields. Oil companies and governments are both concerned about increasing oil recovery from aging resources. To maintain oil production, the mature field must apply the Enhanced Oil Recovery method. water-alternating-gas (WAG) injection is an enhanced oil recovery method designed to improve sweep efficiency during injection with the injected water to control the mobility of . This study will discuss possible corrosion during and water injection and the casing load calculation along with the production tubing during the injection phase. The following study also performed a suitable material selection for the best performance injection. This research was conducted by evaluating casing integrity for simulate water-alternating-gas (WAG) to be applied in the X-well in the Y-field, South Sumatra, Indonesia. Corrosion prediction were performed using Electronic Corrosion Engineer (ECE®) corrosion model and for the strength of tubing which included burst, collapse, and tension of production casing was assessed using Microsoft Excel. This study concluded that for the casing load calculation results in 600 psi of burst pressure, collapse pressure of 2,555.64 psi, and tension of 190,528 lbf. All of these results are still following the K-55 production casing rating. While injecting , the maximum corrosion rate occurs. It has a maximum corrosion rate of 2.02 mm/year and a minimum corrosion rate of 0.36 mm/year. With this value, it is above NORSOK Standard M-001 which is 2 mm/year and needs to be evaluated to prevent the rate to remain stable and not decrease in the following years. To prevent the effect of maximum corrosion rate, the casing material must use a SM13CR (Martensitic Stainless Steel) which is not sour service material.

Comparison of 2507 Duplex and 28 % Cr- Austenitic Stainless Steel Corrosion Behavior for High Pressure and High Temperature (HPHT) in Sour Service Condition with C-ring Experiment

The scarcity of oil and gas resources made High Pressure and High Temperature (HPHT) reservoir attractive to be developed. The sour service environment gives an additional factor in material selection for HPHT reservoir. Austenitic 28 Cr and super duplex stainless steel 2507 (SS 2507) are proposed to be a potential materials candidate for such conditions. C-ring tests were performed to investigate their corrosion behavior, specifically sulfide stress cracking (SSC) and sulfide stress cracking susceptibility. The C-ring tests were done under 2.55 % H2S (31.48 psia) and 50 % CO2 (617.25 psia). The testing was done in static environment conditions. Regardless of good SSC resistance for both materials, different pitting resistance is seen in both materials. The pitting resistance did not follow the general Pitting Resistance Equivalent Number (PREN), since SS 2507 super duplex (PREN &gt; 40) has more pitting density than 28 Cr austenitic stainless steel (PREN &lt; 40). SS 2507 super duplex pit shape tends to be larger but shallower than 28 Cr austenitic stainless steel. 28 Cr austenitic stainless steel has a smaller pit density, yet deeper and isolated.