A wide range of design assumptions must be considered throughout the design phase of a subsea exploration well. In general, conservative parameters must be selected, leading to worst case scenarios, which again may lead to limited operational windows, introduce high cost mitigating actions, or in the worst-case scenario, prevent operations from being carried out.
4Subsea delivered a combination of pre-operational assessments and monitoring during operations for seven consecutive drilling campaigns in the Barents Sea and the North Sea. This included upfront structural design analyses for the conductor and surface casing, as well as subsea well integrity monitoring (SWIM) during well operations.
The measured riser and blowout preventer (BOP) response represented a total of 371 operational days, with the BOP connected to a well with two different semi-submersible drilling rigs.1
The structural integrity of the well foundation and soil support was verified by combining the structured data obtained from measurements with the design information. A sensor system was fitted to the riser and BOP on mobile drilling units to monitor soil and structural integrity.
The typical set-up when drilling a subsea exploration well in a harsh environment is to use a semi-submersible drilling unit with a marine drilling riser and a subsea BOP. The well conductor acts as the foundation of the well and must hence be designed to withstand loads from such operations.
The dominating part of this load is the bending load introduced by the tension and angle in the subsea flexjoint. As previously presented2,3, the magnitude of the wellhead bending load is given by the height of the BOP stack, the submerged weight of the lower marine riser package (LMRP) stack, the total mass of the BOP and the LMRP stack, and the rotational stiffness of the subsea flexjoint.
As illustrated in Figure 1, the height and weight of the BOP stack has increased significantly over the last 40 years due to more stringent safety requirements.
Figure 1. Development of BOP stack height and LMRP submerged weight.4
Additionally, the need for mobile offshore drilling units (MODUs) to cover a broader range of water depths introduces the need for higher pressure class on the subsea flexjoint, which can lead to increased rotational stiffness. The increase in BOP size and flexjoint pressure rating has led to a need for higher structural capacity for the wellhead systems.
Conductor design and conductor analysis
The main task of the conductor is to act as a foundation for the structural loads applied to the wellhead. The conductor must hence be designed to withstand the loads introduced by the riser. The purpose of a conductor analysis is to ensure a robust design. The main content of a typical analysis is summarised in Figure 2.
Figure 2. Main components of a conductor analysis.
The conductor analysis will typically result in a set of operational requirements for the given drilling operations. These will normally be maximum allowable vessel offsets for different scenarios, combined with the maximum allowable wave height for the operation for wells where the dynamic load is significant.
As the design loads increase, the required structural capacity of the conductor housing will have to be increased accordingly. The most common approach is to enhance the conductor size from 30 in. to 36 in. Additionally, this will raise the exposed area towards the soil, and hence, the soil support capacity is also raised with the larger conductor. However, this has a significant cost impact and it requires special handling equipment and additional rig-time to extend the top hole from 36 in. to 42 in., which can increase cement cost.
Soil support – the design challenge
The most important parameter with respect to conductor design (for a satellite well) is the support given by the soil. In the analysis models, the soil support is modelled as soil reaction springs. These include py springs in lateral direction and t-z springs (skin friction) and q-z springs (end bearing) in axial direction. The lateral soil support typically governs the conductor design.
The properties of the supporting soil are typically established from an upfront site survey. This will in most cases include several cone penetration tests (CPTs), in rare cases supported by core samples.
A typical scenario is that the upper layer of the soil is dominated by soft clay with a transition to more firm support 3 – 15 m below the seabed. By far the most important parameter for the conductor design assessment is the distance down to the firm support. CPTs rarely go deeper than 5 – 10 m, often without confirming the elevation of the firm soil layer. It is therefore difficult to get confirmation of the depth of the shift between the soft and the firm soil support. This will often lead to a discrepancy between the high and low estimate of the soil design parameters.
The consequence is illustrated in Figure 3, where a typical bending load distribution along the conductor for the high stiffness and low stiffness design soil is presented.
Figure 3. Typical response from design analysis of upper and lower bound soil profiles.
The bending moment will increase with conductor depth until it reaches a firm soil layer where the load is transferred to the soil. The maximum bending load is the driving factor when determining the required conductor size. The uppermost connector on the conductor is typically located approximately 15 m below the mudline.
The same dataset has also been used to compare different soil models from design analyses with the actual measured response.3 The purpose of including both the low estimate and a best estimate soil parameter is to illustrate the effect of conservatism taken when establishing soil properties from limited data.5
Figure 4 shows where the maximum ratio of the peak load along the conductor to the applied load is plotted as a function of the well stiffness. This shows that the effect of going from the low estimate to the best estimate soil is significant. Therefore, improving the quality of the soil site survey will potentially support reduced conservatism in the conductor design.
Figure 4. Maximum load along the conductor relative to the applied load for all wells based on analysis with different soil profiles.
In addition to affecting the load distribution on the conductor, the well support stiffness also affects the global riser loads, i.e. the dynamic loads. These loads are driven by two opposing effects. The static load due to offset and current is reduced as the well becomes softer. This is because the relative angle between the riser and the BOP is reduced for a softer well support. This leads to reduced static bending load at the wellhead datum for softer wells. The opposing effect is the dynamic amplification of the load over the BOP.
This is part one of a two-part article. Part two is available to read here: https://www.oilfieldtechnology.com/offshore-and-subsea/22042020/drilling-into-the-data--part-two/.
Read the article online at: https://www.oilfieldtechnology.com/offshore-and-subsea/21042020/drilling-into-the-data--part-one/
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