NACE MR0175 vs NACE MR0103

What is the Difference Between NACE MR0175 and NACE MR0103?

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In industries like oil and gas, where equipment and infrastructure are routinely exposed to harsh environments, the selection of materials that can withstand corrosive conditions is crucial. Two key standards that guide material selection for environments containing hydrogen sulfide (H₂S) are NACE MR0175 and NACE MR0103. While both standards aim to prevent sulfide stress cracking (SSC) and other forms of hydrogen-induced damage, they are designed for different applications and environments. This blog provides a comprehensive overview of the differences between these two important standards.

Introduction to NACE Standards

NACE International, now part of the Association for Materials Protection and Performance (AMPP), developed both NACE MR0175 and NACE MR0103 to address the challenges posed by sour service environments—those containing H₂S. These environments can lead to various forms of corrosion and cracking, which can compromise the integrity of materials and potentially lead to catastrophic failures. The primary purpose of these standards is to provide guidelines for selecting materials that can resist these damaging effects.

Scope and Application

NACE MR0175

  • Primary Focus: NACE MR0175, also known as ISO 15156, is primarily intended for the upstream oil and gas industry. This includes exploration, drilling, production, and transportation of hydrocarbons.
  • Environment: The standard covers materials used in sour service environments encountered in oil and gas production. This includes downhole equipment, wellhead components, pipelines, and refineries.
  • Global Use: NACE MR0175 is a globally recognized standard and is widely used in upstream oil and gas operations to ensure the safety and reliability of materials in sour environments.

NACE MR0103

  • Primary Focus: NACE MR0103 is specifically designed for the refining and petrochemical industries, focusing on downstream operations.
  • Environment: The standard applies to process plants where hydrogen sulfide is present, particularly in wet H₂S environments. It is tailored to the conditions found in refining units such as hydroprocessing units, where the risk of sulfide stress cracking is significant.
  • Industry-Specific: Unlike NACE MR0175, which is used in a broader range of applications, NACE MR0103 is more narrowly focused on the refining sector.

Material Requirements

NACE MR0175

  • Material Options: NACE MR0175 offers a wide range of material options, including carbon steels, low-alloy steels, stainless steels, nickel-based alloys, and more. Each material is categorized based on its suitability for specific sour environments.
  • Qualification: Materials must meet stringent criteria to be qualified for use, including resistance to SSC, hydrogen-induced cracking (HIC), and sulfide stress corrosion cracking (SSCC).
  • Environmental Limits: The standard defines limits on H₂S partial pressure, temperature, pH, and other environmental factors that determine the material’s suitability for sour service.

NACE MR0103

  • Material Requirements: NACE MR0103 focuses on materials that can resist SSC in the refining environment. It provides specific criteria for materials such as carbon steels, low-alloy steels, and certain stainless steels.
  • Simplified Guidelines: Compared to MR0175, the material selection guidelines in MR0103 are more straightforward, reflecting the more controlled and consistent conditions typically found in refining operations.
  • Manufacturing Processes: The standard also outlines requirements for welding, heat treatment, and fabrication to ensure materials maintain their resistance to cracking.

Certification and Compliance

NACE MR0175

  • Certification: Compliance with NACE MR0175 is often required by regulatory bodies and is critical for ensuring the safety and reliability of equipment in sour oil and gas operations. The standard is referenced in many international regulations and contracts.
  • Documentation: Detailed documentation is typically required to demonstrate that materials meet the specific criteria outlined in MR0175. This includes chemical composition, mechanical properties, and testing for resistance to sour service conditions.

NACE MR0103

  • Certification: Compliance with NACE MR0103 is typically required in contracts for equipment and materials used in refining and petrochemical plants. It ensures that the selected materials can withstand the specific challenges posed by refinery environments.
  • Simplified Requirements: While still rigorous, the documentation and testing requirements for MR0103 compliance are often less complex than those for MR0175, reflecting the different environmental conditions and risks in refining compared to upstream operations.

Testing and Qualification

NACE MR0175

  • Rigorous Testing: Materials must undergo extensive testing, including laboratory tests for SSC, HIC, and SSCC, to qualify for use in sour environments.
  • Global Standards: The standard aligns with international testing procedures and often requires materials to meet stringent performance criteria in the harshest conditions found in oil and gas operations.

NACE MR0103

  • Targeted Testing: Testing requirements are focused on the specific conditions of refinery environments. This includes testing for resistance to wet H₂S, SSC, and other relevant forms of cracking.
  • Application-Specific: The testing protocols are tailored to the needs of refining processes, which typically involve less severe conditions than those found in upstream operations.

Conclusion

While NACE MR0175 and NACE MR0103 both serve the crucial function of preventing sulfide stress cracking and other forms of environmental cracking in sour service environments, they are designed for different applications.

  • NACE MR0175 is the standard for upstream oil and gas operations, covering a wide range of materials and environmental conditions with rigorous testing and qualification processes.
  • NACE MR0103 is tailored for the refining industry, focusing on downstream operations with simpler, more targeted material selection criteria.

Understanding the differences between these standards is essential for selecting the right materials for your specific application, and ensuring the safety, reliability, and longevity of your infrastructure in environments where hydrogen sulfide is present.

Hydrogen-Induced Cracking HIC

Environmental Cracking: HB, HIC, SWC, SOHIC, SSC, SZC, HSC, HE, SCC

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In industries where materials are subjected to harsh environments—such as oil and gas, chemical processing, and power generation—understanding and preventing environmental cracking is critical. These types of cracking can lead to catastrophic failures, costly repairs, and significant safety risks. This blog post will provide a detailed and professional overview of the various forms of environmental cracking, including their recognition, underlying mechanisms, and strategies for prevention.

1. Hydrogen Blistering (HB)

Recognition:
Hydrogen blistering is characterized by the formation of blisters or bulges on the surface of a material. These blisters are the result of hydrogen atoms penetrating the material and accumulating at internal defects or inclusions, forming hydrogen molecules that create localized high pressure.

Mechanism:
Hydrogen atoms diffuse into the material, typically carbon steel, and recombine into molecular hydrogen at sites of impurities or voids. The pressure from these hydrogen molecules creates blisters, which can weaken the material and lead to further degradation.

Prevention:

  • Material Selection: Use of low-impurity materials, particularly steels with low sulfur content.
  • Protective Coatings: Application of coatings that prevent hydrogen ingress.
  • Cathodic Protection: Implementation of cathodic protection systems to reduce hydrogen absorption.

2. Hydrogen-Induced Cracking (HIC)

Recognition:
Hydrogen-induced cracking (HIC) is identified by internal cracks that often run parallel to the rolling direction of the material. These cracks are typically located along grain boundaries and do not extend to the material’s surface, making them difficult to detect until significant damage has occurred.

Mechanism:
Similar to hydrogen blistering, hydrogen atoms enter the material and recombine to form molecular hydrogen within internal cavities or inclusions. The pressure generated by these molecules causes internal cracking, compromising the material’s structural integrity.

Prevention:

  • Material Selection: Opt for low-sulfur steels with reduced levels of impurities.
  • Heat Treatment: Employ proper heat treatment processes to refine the material’s microstructure.
  • Protective Measures: Use coatings and cathodic protection to inhibit hydrogen absorption.

3. Stress-Oriented Hydrogen-Induced Cracking (SOHIC)

Recognition:
SOHIC is a form of hydrogen-induced cracking that occurs in the presence of external tensile stress. It is recognized by a characteristic stepwise or staircase-like crack pattern, often observed near welds or other high-stress areas.

Mechanism:
The combination of hydrogen-induced cracking and tensile stress leads to a more severe and distinct cracking pattern. The presence of stress exacerbates the effects of hydrogen embrittlement, causing the crack to propagate in a stepwise manner.

Prevention:

  • Stress Management: Implement stress-relief treatments to reduce residual stresses.
  • Material Selection: Use materials with higher resistance to hydrogen embrittlement.
  • Protective Measures: Apply protective coatings and cathodic protection.

4. Sulfide Stress Cracking (SSC)

Recognition:
Sulfide stress cracking (SSC) manifests as brittle cracks in high-strength steels exposed to environments containing hydrogen sulfide (H₂S). These cracks are often intergranular and can propagate rapidly under tensile stress, leading to sudden and catastrophic failure.

Mechanism:
In the presence of hydrogen sulfide, hydrogen atoms are absorbed by the material, leading to embrittlement. This embrittlement reduces the material’s ability to withstand tensile stress, resulting in brittle fracture.

Prevention:

  • Material Selection: Use of sour-service-resistant materials with controlled hardness levels.
  • Environmental Control: Reducing exposure to hydrogen sulfide or using inhibitors to minimize its impact.
  • Protective Coatings: Application of coatings to act as barriers against hydrogen sulfide.

5. Stepwise Cracking (SWC)

Recognition:
Stepwise cracking, also known as stepwise hydrogen cracking, occurs in high-strength steels, particularly in welded structures. It is recognized by a zigzag or staircase-like crack pattern, typically observed near welds.

Mechanism:
Stepwise cracking occurs due to the combined effects of hydrogen embrittlement and residual stress from welding. The crack propagates in a stepwise manner, following the weakest path through the material.

Prevention:

  • Heat Treatment: Use pre- and post-weld heat treatments to reduce residual stresses.
  • Material Selection: Opt for materials with better resistance to hydrogen embrittlement.
  • Hydrogen Bake-Out: Implement hydrogen bake-out procedures after welding to remove absorbed hydrogen.

6. Stress Zinc Cracking (SZC)

Recognition:
Stress zinc cracking (SZC) occurs in zinc-coated (galvanized) steels. It is recognized by intergranular cracks that can lead to the delamination of the zinc coating and subsequent structural failure of the underlying steel.

Mechanism:
SZC is caused by the combination of tensile stress within the zinc coating and exposure to a corrosive environment. The stress within the coating, coupled with environmental factors, leads to intergranular cracking and failure.

Prevention:

  • Coating Control: Ensure proper thickness of the zinc coating to avoid excessive stress.
  • Design Considerations: Avoid sharp bends and corners that concentrate stress.
  • Environmental Control: Reduce exposure to corrosive environments that could exacerbate cracking.

7. Hydrogen Stress Cracking (HSC)

Recognition:
Hydrogen stress cracking (HSC) is a form of hydrogen embrittlement that occurs in high-strength steels exposed to hydrogen. It is characterized by sudden brittle fracture under tensile stress.

Mechanism:
Hydrogen atoms diffuse into the steel, causing embrittlement. This embrittlement significantly reduces the material’s toughness, making it prone to cracking and sudden failure under stress.

Prevention:

  • Material Selection: Choose materials with lower susceptibility to hydrogen embrittlement.
  • Environmental Control: Minimize hydrogen exposure during processing and service.
  • Protective Measures: Apply protective coatings and use cathodic protection to prevent hydrogen ingress.

8. Hydrogen Embrittlement (HE)

Recognition:
Hydrogen embrittlement (HE) is a general term for the loss of ductility and subsequent cracking or fracture of a material due to the absorption of hydrogen. It is often recognized by the sudden and brittle nature of the fracture.

Mechanism:
Hydrogen atoms enter the metal’s lattice structure, causing a significant reduction in ductility and toughness. Under stress, the embrittled material is prone to cracking and failure.

Prevention:

  • Material Selection: Use materials that are resistant to hydrogen embrittlement.
  • Hydrogen Control: Manage hydrogen exposure during manufacturing and service to prevent absorption.
  • Protective Coatings: Apply coatings that prevent hydrogen from entering the material.

9. Stress Corrosion Cracking (SCC)

Recognition:
Stress corrosion cracking (SCC) is characterized by the presence of fine cracks that typically initiate at the material’s surface and propagate through its thickness. SCC occurs when a material is exposed to a specific corrosive environment while under tensile stress.

Mechanism:
SCC results from the combined effects of tensile stress and a corrosive environment. For instance, chloride-induced SCC is a common issue in stainless steels, where chloride ions facilitate crack initiation and propagation under stress.

Prevention:

  • Material Selection: Choose materials with resistance to the specific type of SCC relevant to the environment.
  • Environmental Control: Reduce the concentration of corrosive species, such as chlorides, in the operating environment.
  • Stress Management: Use stress-relief annealing and careful design to minimize residual stresses that can contribute to SCC.

Conclusion

Environmental cracking represents a complex and multifaceted challenge for industries where material integrity is critical. Understanding the specific mechanisms behind each type of cracking—such as HB, HIC, SWC, SOHIC, SSC, SZC, HSC, HE, and SCC—is essential for effective prevention. By implementing strategies like material selection, stress management, environmental control, and protective coatings, industries can significantly reduce the risks associated with these forms of cracking, ensuring the safety, reliability, and longevity of their infrastructure.

As technological advancements continue to evolve, so too will the methods for combating environmental cracking, making ongoing research and development vital to maintaining material integrity in ever-demanding environments.

Constructing Oil Storage Tanks: Calculating Steel Plate Requirements

How to Calculate the Number of Steel Plates for Oil Storage Tanks

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Building oil storage tanks involves precise planning and accurate calculations to ensure structural integrity, safety, and cost-effectiveness. For tanks constructed using carbon steel plates, determining the quantity and arrangement of these plates is crucial. In this blog, we will explore the process of calculating the number of steel plates needed for constructing three cylindrical oil storage tanks, using a specific example to illustrate the steps involved.

Project Specifications

Customer Requirements:

  • Plate Thickness Options: 6mm, 8mm, and 10mm carbon steel plates
  • Plate Dimensions: Width: 2200mm, Length: 6000mm

Tank Specifications:

  • Number of Tanks: 3
  • Individual Tank Volume: 3,000 cubic meters
  • Height: 12 meters
  • Diameter: 15.286 meters

Steps to Calculate Steel Plate Quantities for Three Cylindrical Oil Storage Tanks

Step 1: Calculate the Surface Area of a Single Tank

The surface area of each tank is the sum of the surface areas of the cylindrical shell, the bottom, and the roof.

1. Calculate the Circumference and Shell Area

2. Calculate the Area of the Bottom and Roof

 

Step 2: Calculate the Total Surface Area for All Tanks

Step 3: Determine the Number of Steel Plates Required

Step 4: Allocate Plate Thickness

To optimize the tanks’ structural integrity and cost, allocate different plate thicknesses for various parts of each tank:

  • 6mm Plates: Use for the roofs, where structural stress is lower.
  • 8mm Plates: Apply to the upper sections of the tank shells, where stress is moderate.
  • 10mm Plates: Use for the bottoms and lower sections of the shells, where the stress is highest due to the weight of the stored oil.

Step 5: Example Allocation of Plates for Each Tank

Bottom Plates:

  • Required Area per Tank: 183.7 square meters
  • Plate Thickness: 10mm
  • Number of Plates per Tank: [183.7/13.2] plates
  • Total for 3 Tanks: 14 × 3 plates

Shell Plates:

  • Required Area per Tank: 576 square meters
  • Plate Thickness: 10mm (lower section), 8mm (upper section)
  • Number of Plates per Tank: [576/13.2] plates
    • Lower Section (10mm): Approximately 22 plates per tank
    • Upper Section (8mm): Approximately 22 plates per tank
  • Total for 3 Tanks: 44 × 3 plates

Roof Plates:

  • Required Area per Tank: 183.7 square meters
  • Plate Thickness: 6mm
  • Number of Plates per Tank: [183.7/13.2] plates
  • Total for 3 Tanks: 14 × 3 = plates

Considerations for Accurate Calculations

  • Corrosion Allowance: Include additional thickness to account for future corrosion.
  • Wastage: Consider material wastage due to cutting and fitting, typically adding 5-10% extra material.
  • Design Codes: Ensure compliance with relevant design codes and standards, such as API 650, when determining plate thickness and tank design.

Conclusion

Constructing oil storage tanks with carbon steel plates involves precise calculations to ensure material efficiency and structural integrity. By accurately determining the surface area and considering the appropriate plate thicknesses, you can estimate the number of plates required to build tanks that meet industry standards and customer requirements. These calculations form the foundation for successful tank construction, enabling efficient material procurement and project planning. Whether for a new project or retrofitting existing tanks, this approach ensures robust and reliable oil storage solutions that align with engineering best practices. If you have a new LNG, aviation fuel, or crude oil storage tank project, please feel free to contact [email protected] for an optimal steel plate quote.

3LPE Coating vs 3LPP Coating

3LPE vs 3LPP: Comprehensive Comparison of Pipeline Coatings

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Pipeline coatings are critical in protecting steel pipelines from corrosion and other environmental factors. Among the most commonly used coatings are 3-Layer Polyethylene (3LPE) and 3-Layer Polypropylene (3LPP) coatings. Both coatings offer robust protection, but they differ in terms of application, composition, and performance. This blog will provide a detailed comparison between 3LPE and 3LPP coatings, focusing on five key areas: coating selection, coating composition, coating performance, construction requirements, and construction process.

1. Coating Selection

3LPE Coating:

  • Usage: 3LPE is widely used in the oil and gas industry for onshore and offshore pipelines. It is particularly suitable for environments where moderate temperature resistance and excellent mechanical protection are required.
  • Temperature Range: The 3LPE coating is typically used for pipelines operating at temperatures ranging from -40°C to 80°C.
  • Cost Consideration: 3LPE is generally more cost-effective than 3LPP, making it a popular choice for projects with budget constraints where the temperature requirements are within the range it supports.

3LPP Coating:

  • Usage: 3LPP is favored in high-temperature environments, such as deepwater offshore pipelines and pipelines transporting hot fluids. It is also used in areas where superior mechanical protection is needed.
  • Temperature Range: 3LPP coatings can withstand higher temperatures, typically between -20°C to 140°C, making them suitable for more demanding applications.
  • Cost Consideration: 3LPP coatings are more expensive due to their superior temperature resistance and mechanical properties, but they are necessary for pipelines that operate in extreme conditions.

Selection Summary: The choice between 3LPE and 3LPP primarily depends on the operating temperature of the pipeline, the environmental conditions, and budget considerations. 3LPE is ideal for moderate temperatures and cost-sensitive projects, while 3LPP is preferred for high-temperature environments and where enhanced mechanical protection is essential.

2. Coating Composition

3LPE Coating Composition:

  • Layer 1: Fusion Bonded Epoxy (FBE): The innermost layer provides excellent adhesion to the steel substrate and acts as the primary corrosion protection layer.
  • Layer 2: Copolymer Adhesive: This layer bonds the FBE layer to the polyethylene topcoat, ensuring strong adhesion and additional corrosion protection.
  • Layer 3: Polyethylene (PE): The outer layer of polyethylene provides mechanical protection against physical damage during handling, transportation, and installation.

3LPP Coating Composition:

  • Layer 1: Fusion Bonded Epoxy (FBE): Similar to 3LPE, the FBE layer in 3LPP serves as the primary corrosion protection and bonding layer.
  • Layer 2: Copolymer Adhesive: This adhesive layer bonds the FBE to the polypropylene topcoat, ensuring strong adhesion.
  • Layer 3: Polypropylene (PP): The outer layer of polypropylene offers superior mechanical protection and higher temperature resistance compared to polyethylene.

Composition Summary: Both coatings share a similar structure, with an FBE layer, a copolymer adhesive, and an outer protective layer. However, the outer layer material differs—polyethylene in 3LPE and polypropylene in 3LPP—leading to differences in performance characteristics.

3. Coating Performance

3LPE Coating Performance:

  • Temperature Resistance: 3LPE performs well in moderate temperature environments but may not be suitable for temperatures exceeding 80°C.
  • Mechanical Protection: The polyethylene outer layer provides excellent resistance to physical damage, making it suitable for onshore and offshore pipelines.
  • Corrosion Resistance: The combination of FBE and PE layers offers robust protection against corrosion, especially in humid or wet environments.
  • Chemical Resistance: 3LPE offers good resistance to chemicals but is less effective in environments with aggressive chemical exposure compared to 3LPP.

3LPP Coating Performance:

  • Temperature Resistance: 3LPP is designed to withstand higher temperatures, up to 140°C, making it ideal for pipelines transporting hot fluids or located in high-temperature environments.
  • Mechanical Protection: The polypropylene layer provides superior mechanical protection, especially in deepwater offshore pipelines where external pressures and physical stress are higher.
  • Corrosion Resistance: 3LPP offers excellent corrosion protection, similar to 3LPE, but with better performance in higher temperature environments.
  • Chemical Resistance: 3LPP has superior chemical resistance, making it more suitable for environments with aggressive chemicals or hydrocarbons.

Performance Summary: 3LPP outperforms 3LPE in high-temperature environments and provides better mechanical and chemical resistance. However, 3LPE is still highly effective for moderate temperatures and less aggressive environments.

4. Construction Requirements

3LPE Construction Requirements:

  • Surface Preparation: Proper surface preparation is crucial for the effectiveness of the 3LPE coating. The steel surface must be cleaned and roughened to achieve the necessary adhesion for the FBE layer.
  • Application Conditions: The application of the 3LPE coating must be carried out in a controlled environment to ensure the proper adhesion of each layer.
  • Thickness Specifications: The thickness of each layer is critical, with the total thickness typically ranging from 1.8 mm to 3.0 mm, depending on the pipeline’s intended use.

3LPP Construction Requirements:

  • Surface Preparation: Like 3LPE, surface preparation is key. The steel must be cleaned to remove any contaminants and roughened to ensure proper adhesion of the FBE layer.
  • Application Conditions: The application process for 3LPP is similar to that of 3LPE but often requires more precise control due to the higher temperature resistance of the coating.
  • Thickness Specifications: 3LPP coatings are typically thicker than 3LPE, with the total thickness ranging from 2.0 mm to 4.0 mm, depending on the specific application.

Construction Requirements Summary: Both 3LPE and 3LPP require meticulous surface preparation and controlled application environments. However, 3LPP coatings generally require thicker applications to achieve their enhanced protective qualities.

5. Construction Process

3LPE Construction Process:

  1. Surface Cleaning: The steel pipe is cleaned using methods like abrasive blasting to remove rust, scale, and other contaminants.
  2. FBE Application: The cleaned pipe is preheated, and the FBE layer is applied electrostatically, providing a strong bond to the steel.
  3. Adhesive Layer Application: A copolymer adhesive is applied over the FBE layer, bonding the FBE to the outer polyethylene layer.
  4. PE Layer Application: The polyethylene layer is extruded onto the pipe, providing mechanical protection and additional corrosion resistance.
  5. Cooling and Inspection: The coated pipe is cooled, inspected for defects, and prepared for transportation.

3LPP Construction Process:

  1. Surface Cleaning: Similar to 3LPE, the steel pipe is thoroughly cleaned to ensure proper adhesion of the coating layers.
  2. FBE Application: The FBE layer is applied to the preheated pipe, serving as the primary corrosion protection layer.
  3. Adhesive Layer Application: A copolymer adhesive is applied over the FBE layer, ensuring a strong bond with the polypropylene topcoat.
  4. PP Layer Application: The polypropylene layer is applied through extrusion, providing superior mechanical and temperature resistance.
  5. Cooling and Inspection: The pipe is cooled, inspected for defects, and prepared for deployment.

Construction Process Summary: The construction processes for 3LPE and 3LPP are similar, with differences primarily in the materials used for the outer protective layer. Both processes require careful control of temperature, cleanliness, and layer thickness to ensure optimal performance.

Conclusion

Choosing between 3LPE and 3LPP coatings depends on several factors, including the operating temperature, environmental conditions, mechanical stress, and budget.

  • 3LPE is ideal for pipelines operating at moderate temperatures and where cost is a significant consideration. It provides excellent corrosion resistance and mechanical protection for most onshore and offshore applications.
  • 3LPP, on the other hand, is the preferred choice for high-temperature environments and applications requiring superior mechanical protection. Its higher cost is justified by its enhanced performance in demanding conditions.

Understanding the specific requirements of your pipeline project is essential in selecting the appropriate coating. Both 3LPE and 3LPP have their strengths and applications, and the right choice will ensure long-term protection and durability for your pipeline infrastructure.

Exploring the Vital Role of Steel Pipes in Oil & Gas Exploration

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I. The Basic Knowledge of the Pipe for Oil and Gas Industry

1. Terminology Explanation

API: Abbreviation of American Petroleum Institute.
OCTG: Abbreviation of Oil Country Tubular Goods, including Oil Casing Pipe, Oil Tubing, Drill Pipe, Drill Collar, Drill Bits, Sucker Rod, Pup joints, etc.
Oil Tubing: Tubing is used in oil wells for oil extraction, gas extraction, water injection, and acid fracturing.
Casing: Tubing that is lowered from the ground surface into a drilled borehole as a liner to prevent wall collapse.
Drill Pipe: Pipe used for drilling boreholes.
Line Pipe: Pipe used to transport oil or gas.
Couplings: Cylinders used to connect two threaded pipes with internal threads.
Coupling Material: Pipe used for manufacturing couplings.
API Threads: Pipe threads specified by API 5B standard, including oil pipe round threads, casing short round threads, casing long round threads, casing partial trapezoidal threads, line pipe threads, and so on.
Premium Connection: Non-API threads with special sealing properties, connection properties, and other properties.
Failures: deformation, fracture, surface damage, and loss of original function under specific service conditions.
Main Forms of Failure: crushing, slipping, rupture, leakage, corrosion, bonding, wear, and so on.

2. Petroleum Related Standards

API Spec 5B, 17th Edition – Specification for Threading, Gauging, and Thread Inspection of Casing, Tubing, and Line Pipe Threads
API Spec 5L, 46th Edition – Specification for Line Pipe
API Spec 5CT, 11th Edition – Specification for Casing and Tubing
API Spec 5DP, 7th Edition – Specification for Drill Pipe
API Spec 7-1, 2nd Edition – Specification for Rotary Drill Stem Elements
API Spec 7-2, 2nd Edition – Specification for Threading and Gauging of Rotary Shouldered Thread Connections
API Spec 11B, 24th Edition – Specification for Sucker Rods, Polished Rods and Liners, Couplings, Sinker Bars, Polished Rod Clamps, Stuffing Boxes and Pumping Tees
ISO 3183:2019 – Petroleum and Natural Gas Industries — Steel Pipe for Pipeline Transportation Systems
ISO 11960:2020 – Petroleum and Natural Gas Industries — Steel Pipes for Use as Casing or Tubing for Wells
NACE MR0175 / ISO 15156:2020 – Petroleum and Natural Gas Industries — Materials for Use in H2S-Containing Environments in Oil and Gas Production

II. Oil Tubing

1. Classification of Oil Tubing

Oil Tubing is divided into Non-Upsetted Oil Tubing (NU), External Upsetted Oil Tubing (EU), and Integral Joint (IJ) Oil Tubing. NU oil tubing means that the end of the tubing is of normal thickness and directly turns the thread and brings the couplings. Upsetted tubing means that the ends of both tubes are externally Upsetted, then threaded and coupled. Integral Joint tubing means that one end of the tube is Upsetted with external threads and the other end is Upsetted with internal threads and connected directly without couplings.

2. Function of Oil Tubing

① Extraction of oil and gas: after the oil and gas wells are drilled and cemented, the tubing is placed in the oil casing to extract oil and gas to the ground.
② Water injection: when the downhole pressure is insufficient, inject water into the well through the tubing.
③ Steam injection: In thick oil hot recovery, steam is to be input into the well with insulated oil tubing.
④ Acidification and fracturing: In the late stage of well drilling or to improve the production of oil and gas wells, it is necessary to input acidification and fracturing medium or curing material to the oil and gas layer, and the medium and the curing material are transported through the oil tubing.

3. Steel Grade of Oil Tubing

The steel grades of oil tubing are H40, J55, N80, L80, C90, T95, P110.
N80 is divided into N80-1 and N80Q, the two have the same tensile properties of the same, the two differences are the delivery status and impact performance differences, N80-1 delivery by normalized state or when the final rolling temperature is greater than the critical temperature Ar3 and tension reduction after air cooling and can be used to find hot rolling instead of normalized, impact and non-destructive testing are not required; N80Q must be tempered (quenched and tempered) Heat treatment, impact function should be in line with the provisions of API 5CT, and should be non-destructive testing.
L80 is divided into L80-1, L80-9Cr and L80-13Cr. Their mechanical properties and delivery status are the same. Differences in use, production difficulty, and price, L80-1 for the general type, L80- 9Cr and L80-13Cr are high corrosion resistance tubing, production difficulty, expensive, and usually used in heavy corrosion wells.
C90 and T95 are divided into 1 and 2 types, namely C90-1, C90-2 and T95-1, T95-2.

4. The Oil Tubing Commonly Used Steel Grade, Steel Name and Delivery Status

J55 (37Mn5) NU Oil Tubing: Hot rolled instead of Normalised
J55 (37Mn5) EU Oil Tubing: Full-length Normalized after upsetting
N80-1 (36Mn2V) NU Oil Tubing: Hot-rolled instead of Normalised
N80-1 (36Mn2V) EU Oil Tubing: Full-length Normalized after upsetting
N80-Q (30Mn5) Oil Tubing: 30Mn5, Full-length Tempering
L80-1 (30Mn5) Oil Tubing: 30Mn5, Full-length Tempering
P110 (25CrMnMo) Oil Tubing: 25CrMnMo, Full-length Tempering
J55 (37Mn5) Coupling: Hot rolled on-line Normalised
N80 (28MnTiB) Coupling: Full-length Tempering
L80-1 (28MnTiB) Coupling: Full-length Tempered
P110 (25CrMnMo) Coupling: Full-length Tempering

III. Casing Pipe

1. Classification and Role of Casing

The casing is the steel pipe that supports the wall of oil and gas wells. Several layers of casing are used in each well according to different drilling depths and geological conditions. Cement is used to cement the casing after it is lowered into the well, and unlike oil pipe and drill pipe, it cannot be reused and belongs to disposable consumable materials. Therefore, the consumption of casing accounts for more than 70 percent of all oil well pipes. The casing can be divided into conductor casing, intermediate casing, production casing, and liner casing according to its use, and their structures in oil wells are shown in Figure 1.

①Conductor Casing: Typically using API grades K55, J55, or H40, conductor casing stabilizes the wellhead and isolates shallow aquifers with diameters commonly around 20 inches or 16 inches.

②Intermediate Casing: Intermediate casing, often made from API grades K55, N80, L80, or P110, is used to isolate unstable formations and varying pressure zones, with typical diameters of 13 3/8 inches, 11 3/4 inches, or 9 5/8 inches.

③Production Casing: Constructed from high-grade steel such as API grades J55, N80, L80, P110, or Q125, production casing is designed to withstand production pressures, commonly with diameters of 9 5/8 inches, 7 inches, or 5 1/2 inches.

④Liner Casing: Liners extend the wellbore into the reservoir, using materials like API grades L80, N80, or P110, with typical diameters of 7 inches, 5 inches, or 4 1/2 inches.

⑤Tubing: Tubing transports hydrocarbons to the surface, using API grades J55, L80, or P110, and is available in diameters of 4 1/2 inches, 3 1/2 inches, or 2 7/8 inches.

IV. Drill pipe

1. Classification and Function of Pipe for Drilling Tools

The square drill pipe, drill pipe, weighted drill pipe, and drill collar in drilling tools form the drill pipe. The drill pipe is the core drilling tool that drives the drill bit from the ground to the bottom of the well, and it is also a channel from the ground to the bottom of the well. It has three main roles:

① To transmit torque to drive the drill bit to drill;

② To rely on its weight to the drill bit to break the pressure of the rock at the bottom of the well;

③ To transport washing fluid, that is, drilling mud through the ground through the high-pressure mud pumps, drilling column into the borehole flow into the bottom of the well to flush the rock debris and cool the drill bit, and carry the rock debris through the outer surface of the column and the wall of the well between the annulus to return to the ground, to achieve the purpose of drilling the well.

The drill pipe in the drilling process to withstand a variety of complex alternating loads, such as tensile, compression, torsion, bending, and other stresses, the inner surface is also subject to high-pressure mud scouring and corrosion.
(1) Square Drill Pipe: square drill pipe has two kinds quadrilateral type and hexagonal type, China’s petroleum drill pipe each set of drill columns usually uses a quadrilateral type drill pipe. Its specifications are 63.5mm (2-1/2 inches), 88.9mm (3-1/2 inches), 107.95mm (4-1/4 inches), 133.35mm (5-1/4 inches), 152.4mm (6 inches) and so on. Usually, the length used is 12~14.5m.
(2) Drill Pipe: The drill pipe is the main tool for drilling wells, connected to the lower end of the square drill pipe, and as the drilling well continues to deepen, the drill pipe keeps lengthening the drill column one after another. The specifications of drill pipe are: 60.3mm (2-3/8 inches), 73.03mm (2-7/8 inches), 88.9mm (3-1/2 inches), 114.3mm (4-1/2 inches), 127mm (5 inches), 139.7mm (5-1/2 inches) and so on.
(3) Heavy Duty Drill Pipe: A weighted drill pipe is a transitional tool connecting the drill pipe and drill collar, which can improve the force condition of the drill pipe and increase the pressure on the drill bit. The main specifications of the weighted drill pipe are 88.9mm (3-1/2 inches) and 127mm (5 inches).
(4) Drill Collar: the drill collar is connected to the lower part of the drill pipe, which is a special thick-walled pipe with high rigidity, exerting pressure on the drill bit to break the rock, and playing a guiding role when drilling a straight well. The common specifications of drill collars are 158.75mm (6-1/4 inches), 177.85mm (7 inches), 203.2mm (8 inches), 228.6mm (9 inches) and so on.

V. Line pipe

1. Classification of Line Pipe

Line pipe is used in the oil and gas industry for the transmission of oil, refined oil, natural gas, and water pipelines with the abbreviation of steel pipe. Conveying oil, and gas pipelines is mainly divided into mainline pipelines, branch line pipelines, and urban pipeline network pipelines three kinds of mainline pipeline transmission of the usual specifications for  ∅406 ~ 1219mm, wall thickness of 10 ~ 25mm, steel grade X42 ~ X80; branch line pipeline and urban pipeline network pipelines are usually specification for the ∅114 ~ 700mm, wall thickness of 6 ~ 20mm, the steel grade for the X42 ~ X80. The steel grade is X42～X80. Line pipe is available as welded type and seamless type. Welded Line Pipe is used more than Seamless Line Pipe.

2. Standard of Line Pipe

API Spec 5L – Specification for Line Pipe
ISO 3183 – Petroleum and Natural Gas Industries — Steel Pipe for Pipeline Transportation Systems

3. PSL1 and PSL2

PSL is the abbreviation of Product Specification Level. Line pipe product specification level is divided into PSL 1 and PSL 2, can also be said that the quality level is divided into PSL 1 and PSL 2. PSL 2 is higher than PSL 1, the 2 specification levels not only have different test requirements, but the chemical composition and mechanical properties requirements are different, so according to API 5L order, the terms of the contract in addition to specifying the specifications, steel grade and other common indicators, but also must indicate the product Specification level, that is, PSL 1 or PSL 2. PSL 2 in the chemical composition, tensile properties, impact power, non-destructive testing, and other indicators are stricter than PSL 1.

4. Line Pipe Steel Grade, Chemical Composition and Mechanical Properties

Line pipe steel grade from low to high is divided into: A25, A, B, X42, X46, X52, X60, X65, X70, and X80. For the detailed Chemical Composition and Mechanical Properties, please refer to API 5L Specification, 46th Edition Book.

5. Line Pipe Hydrostatic Test and Non-destructive Examination Requirements

Line pipe should be done branch by branch hydraulic test, and the standard does not allow non-destructive generation of hydraulic pressure, which is also a big difference between the API standard and our standards. PSL 1 does not require non-destructive testing, PSL 2 should be non-destructive testing branch by branch.

VI. Premium Connections

1. Introduction of Premium Connections

Premium Connection is a pipe thread with a special structure different from the API thread. Although the existing API threaded oil casing is widely used in oil well exploitation, its shortcomings are clearly shown in the special environment of some oil fields: the API round threaded pipe column, although its sealing performance is better, the tensile force borne by the threaded part is only equivalent to 60% to 80% of the strength of the pipe body, and thus it can’t be used in the exploitation of deep wells; the API biased trapezoidal threaded pipe column, although its tensile performance is much higher than that of the API round threaded connection, its sealing performance is not so good. Although the tensile performance of the column is much higher than that of the API round thread connection, its sealing performance is not very good, so it can not be used in the exploitation of high-pressure gas wells; in addition, the threaded grease can only play its role in the environment with the temperature below 95℃, so it can not be used in the exploitation of high-temperature wells.

Compared with the API round thread and partial trapezoidal thread connection, the premium connection has made breakthrough progress in the following aspects:

(1) Good sealing, through the elasticity and metal sealing structure design, makes the joint gas sealing resistant to reaching the limit of the tubing body within the yield pressure;

(2) High strength of the connection, connecting with special buckle connection of oil casing, its connection strength reaches or exceeds the strength of the tubing body, to solve the problem of slippage fundamentally;

(3) By the Material selection and surface treatment process improvement, basically solved the problem of thread sticking buckle;

(4) Through the optimization of the structure, so that the joint stress distribution is more reasonable and more conducive to the resistance to stress corrosion;

(5) Through the shoulder structure of the reasonable design, so that the operation of the buckle on the operation is easier to carry out.

At present, the oil and gas industry boasts over 100 patented premium connections, representing significant advancements in pipe technology. These specialized thread designs offer superior sealing capabilities, increased connection strength, and enhanced resistance to environmental stresses. By addressing challenges such as high pressures, corrosive environments, and temperature extremes, these innovations ensure greater reliability and efficiency in oil well operations worldwide. Continual research and development in premium connections underscore their pivotal role in supporting safer and more productive drilling practices, reflecting an ongoing commitment to technological excellence in the energy sector.

VAM® Connection: Known for its robust performance in challenging environments, VAM® connections feature advanced metal-to-metal sealing technology and high torque capabilities, ensuring reliable operations in deep wells and high-pressure reservoirs.

TenarisHydril Wedge Series: This series offers a range of connections such as Blue®, Dopeless®, and Wedge 521®, known for their exceptional gas-tight sealing and resistance to compression and tension forces, enhancing operational safety and efficiency.

TSH® Blue: Designed by Tenaris, TSH® Blue connections utilize a proprietary double shoulder design and a high-performance thread profile, providing excellent fatigue resistance and ease of make-up in critical drilling applications.

Grant Prideco™ XT® Connection: Engineered by NOV, XT® connections incorporate a unique metal-to-metal seal and a robust thread form, ensuring superior torque capacity and resistance to galling, thereby extending the operational life of the connection.

Hunting Seal-Lock® Connection: Featuring a metal-to-metal seal and a unique thread profile, the Seal-Lock® connection by Hunting is renowned for its superior pressure resistance and reliability in both onshore and offshore drilling operations.

Conclusion

In conclusion, the intricate network of pipes crucial to the oil and gas industry encompasses a wide array of specialized equipment designed to withstand rigorous environments and complex operational demands. From the foundational casing pipes that support and protect well walls to the versatile tubing used in extraction and injection processes, each type of pipe serves a distinct purpose in the exploration, production, and transportation of hydrocarbons. Standards like API specifications ensure uniformity and quality across these pipes, while innovations such as premium connections enhance performance in challenging conditions. As technology evolves, these critical components continue to advance, driving efficiency and reliability in global energy operations. Understanding these pipes and their specifications underscores their indispensable role in the modern energy sector’s infrastructure.

Super 13Cr SMSS 13Cr Casing and Tubing

SMSS 13Cr and DSS 22Cr in H₂S/CO₂-Oil-Water Environment

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The corrosion behaviors of Super Martensitic Stainless Steel (SMSS) 13Cr and Duplex Stainless Steel (DSS) 22Cr in an H₂S/CO₂-oil-water environment are of significant interest, especially in the oil and gas industry, where these materials are often exposed to such harsh conditions. Here’s an overview of how each material behaves under these conditions:

1. Super Martensitic Stainless Steel (SMSS) 13Cr:

  • Composition: SMSS 13Cr typically contains around 12-14% Chromium, with small amounts of Nickel and Molybdenum. The high Chromium content gives it good resistance to corrosion, while the martensitic structure provides high strength.
  • Corrosion Behavior:
    • CO₂ Corrosion: SMSS 13Cr shows moderate resistance to CO₂ corrosion, primarily due to the formation of a protective chromium oxide layer. However, in the presence of CO₂, there is a risk of localized corrosion such as pitting and crevice corrosion.
    • H₂S Corrosion: The presence of H₂S increases the risk of sulfide stress cracking (SSC) and hydrogen embrittlement. SMSS 13Cr is somewhat resistant but not immune to these forms of corrosion, especially at higher temperatures and pressures.
    • Oil-Water Environment: The presence of oil can sometimes provide a protective barrier, reducing the exposure of the metal surface to corrosive agents. However, water, particularly in the form of brine, can be highly corrosive. The balance of oil and water phases can significantly influence the overall corrosion rate.
  • Common Issues:
    • Sulfide Stress Cracking (SSC): The martensitic structure, while strong, is susceptible to SSC in the presence of H₂S.
    • Pitting and Crevice Corrosion: These are significant concerns, especially in environments with chlorides and CO₂.

2. Duplex Stainless Steel (DSS) 22Cr:

  • Composition: DSS 22Cr contains around 22% Chromium, with approximately 5% Nickel, 3% Molybdenum, and a balanced austenite-ferrite microstructure. This gives DSS excellent corrosion resistance and high strength.
  • Corrosion Behavior:
    • CO₂ Corrosion: DSS 22Cr has superior resistance to CO₂ corrosion compared to SMSS 13Cr. The high chromium content and the presence of molybdenum help in forming a stable and protective oxide layer that resists corrosion.
    • H₂S Corrosion: DSS 22Cr is highly resistant to H₂S-induced corrosion, including SSC and hydrogen embrittlement. The balanced microstructure and alloy composition help in mitigating these risks.
    • Oil-Water Environment: DSS 22Cr performs well in mixed oil-water environments, resisting both general and localized corrosion. The presence of oil can enhance corrosion resistance by forming a protective film, but this is less critical for DSS 22Cr due to its inherent corrosion resistance.
  • Common Issues:
    • Stress Corrosion Cracking (SCC): While more resistant than SMSS 13Cr, DSS 22Cr can still be susceptible to SCC under certain conditions, such as high chloride concentrations at elevated temperatures.
    • Localized Corrosion: DSS 22Cr is generally very resistant to pitting and crevice corrosion, but under extreme conditions, these can still occur.

Comparative Summary:

  • Corrosion Resistance: DSS 22Cr generally offers superior corrosion resistance compared to SMSS 13Cr, especially in environments with both H₂S and CO₂.
  • Strength and Toughness: SMSS 13Cr has higher strength but is more susceptible to corrosion issues like SSC and pitting.
  • Application Suitability: DSS 22Cr is often preferred in environments with higher corrosion risks, such as those with high levels of H₂S and CO₂, whereas SMSS 13Cr might be selected for applications requiring higher strength where corrosion risks are moderate.

Conclusion:

When selecting between SMSS 13Cr and DSS 22Cr for use in H₂S/CO₂-oil-water environments, DSS 22Cr is typically the better choice for resisting corrosion, particularly in more aggressive environments. However, the final decision should consider the specific conditions, including temperature, pressure, and the relative concentrations of H₂S and CO₂.