Casing and Tubing Design Criteria for Oil and Gas Wells
The design considerations and selection criteria for casing and tubing in oil and gas wells, including setting depths, loads, load cases, design factors, size, weight, grade, material, and requirements for corrosion-resistant materials, are discussed below.
1. Criteria for Selecting Casing Depths ✓
Selecting the appropriate casing setting depths is vital for effective well design, as it significantly impacts safety, stability, and environmental protection. When making this decision, it's important to conduct a comprehensive analysis of the pore pressure and fracture pressure gradients of the formations we intend to drill into. These pressures are plotted against depth to identify points where the mud weight needed to control pore pressure exceeds the fracture gradient, risking formation fracture or blowout. Casing is set to isolate these zones, allowing safe drilling to continue.
Key Considerations
Pore and Fracture Pressure Analysis: Pore pressure is estimated from offset wells or seismic data for wildcat wells, while fracture pressure is calculated using equations like the Eaton equation.
Mud Density Margins: A trip margin ensures safety during tripping, while a kick margin prevents fractures during kicks.
Environmental Protection: Surface casing is typically set at a minimum depth to protect freshwater aquifers.
Additional Factors: Lost circulation zones, pressure-depleted zones, troublesome shale, and regulatory requirements influence depth selection. The conductor casing depth is set based on the ground resistance measured during driving.
Pore and fracture pressure are plotted on a chart. Another profile is plotted for the planned mud weight by adding an overbalance margin to the pore pressure. This overbalance is usually governed by the company's policy and regulations to ensure safe drilling and tripping operations. A safety margin is also considered by reducing the fracture gradient to avoid fracturing the formation. This results in the safe operating window used to select the casing setting depths. The safe setting depths identified through this process are refined by considering environmental, regulatory, and other factors, such as formation characteristics.
2. Primary Casing Loads - Burst, Collapse, Tensile, Triaxial ✓
The casing must withstand various mechanical loads to maintain well integrity throughout its lifetime. The primary loads are:
Burst Load: Burst load is the Internal pressure from well fluids or gas kicks that could rupture the casing. This is critical during drilling or production, especially when high-pressure conditions occur during well control operations, integrity tests, squeeze cementing, or during production due to a tubing leak, among other scenarios. The Burst load is calculated as the difference between internal and external pressure. The maximum burst load will be considered under zero external pressure and no axial loading. In that case, the force required to burst a pipe from the inside is counteracted only by the strength of the pipe walls.
Collapse Load: The collapse load refers to the difference between external pressure, stemming from formation or hydrostatic forces, and the internal pressure within the casing. For example, during operations such as cementing, the casing is subjected to high external loads. If the internal pressure drops significantly, perhaps due to well evacuation scenarios, the external pressure at certain points could surpass the casing's collapse rating, leading to a potential pipe collapse.
Tensile Load: The tensile or axial load is determined by adding together the weight of the casing string, the buoyancy effects of the well fluids, and any additional loads that may arise from operations such as setting the casing or conducting pressure tests. Numerous factors can affect this load, such as the depth of the well, the density of the mud, the height of the fluid column, changes in temperature, and the properties of the casing material.
Triaxial Load: The fundamental concept in casing design is that a failure occurs when the combined stresses within the pipe wall exceed the yield strength of the material.. The calculations are based on a uniaxial stress state in which only one of the three principal stresses is nonzero. However, the pipe in the wellbore is always subjected to combined loading conditions where three principal stresses are present. Triaxial analysis uses von Mises' criteria to assess overall stress. Triaxial stress is not a true stress but is a theoretical value that allows a generalized three-dimensional stress state to be compared with a uniaxial failure criterion.
3. Casing Design Factors ✓
Casing design involves defining load cases that simulate the most severe conditions the casing may encounter. Design factors provide safety margins for selecting the appropriate grade of casing pipe. Load cases vary by casing type (surface, intermediate, production) and well phase.
API 5C3, "Calculating Performance Properties of Pipe Used in Oil and Natural Gas Industries," provides methods for calculating the performance properties (burst, collapse, and axial tension) of casing and tubing. API TR 5C3 (Technical Report) and API RP 5C1 (Recommended Practice) offer guidance on design considerations. Sometimes, API 5CT is also referenced for material specifications and connections.
The standard range for design factors used in the industry to ensure casing/tubing integrity in oil and gas wells is as follows:
Burst 1.10 – 1.25
Collapse 1.00 – 1.25
Tensile 1.3
4. Casing Selection Criteria and Influencing Factors ✓
Selecting the appropriate casing specifications involves balancing mechanical requirements, well design, and economic considerations, guided by standards such as API 5CT.
Size: Well design is typically a bottom-up process. Based on reservoir potential and production objectives, the production tubing size is established, which defines the minimum production casing ID. The wellbore diameter and the need to fit subsequent strings determine the combination of hole size and casing size. Deeper wells often require more casing strings.
Weight: Casing weight reflects the wall thickness and affects pipe strength. Heavier weights provide higher burst and collapse resistance. The casing weight is selected based on load calculations, rig capacity, and well design requirements.
Grade: The casing grade indicates the steel's yield strength. Higher grades are used for deeper, high-pressure wells, while non-API grades may be used for special applications, such as resistance to H2S. Casing grades are decided based on casing load calculations and design considerations.
Material: Carbon steel, which typically contains around 0.3% carbon, is often normalized with manganese to enhance its properties. It is frequently chosen for its cost-effectiveness and widespread availability in various industries. In situations where corrosion resistance is a critical factor, corrosion-resistant alloys (CRAs) such as 13Cr and 22Cr are preferred due to their superior performance in hostile environments. These alloys offer superior durability and extended lifespan, making them perfect for situations where contact with corrosive materials is unavoidable.
Factors Influencing Casing Selection
Well Depth and Pressure: Deeper wells require stronger, thicker casing.
Geological Conditions: Corrosive formations or high temperatures necessitate specific grades or materials.
Regulatory Standards: Compliance with API 5CT and local regulations to ensure safety and performance.
Economic Considerations for balancing the cost with performance and longevity.
5. Special Material Selection Criteria for Casing and Tubing ✓
Standard carbon steel may fail in wells with corrosive or extreme conditions, so corrosion-resistant alloys (CRAs) are required to ensure longevity and integrity. Specific well conditions and corrosion mechanisms drive the selection of CRAs. The following well conditions may necessitate special CRA material for casing and tubing:
High-pressure, High-Temperature (HPHT) Wells: Corrosion accelerates at pressures greater than 15,000 psi and temperatures greater than 350°F.
Corrosive Gases: Presence of a corrosive environment, such as the presence of CO2 and H2S.
Chloride-Rich Environments: High chloride levels lead to pitting and crevice corrosion, which is common in offshore wells.
Deepwater and Offshore Settings: Seawater and harsh conditions increase the risk of corrosion.
Shale gas production involves corrosive fluids and high pressures.
Carbon Capture and Storage: The CO2 injection wells require materials resistant to CO2.