Can high-resolution reprocessed data replace the traditional 2D high-resolution seismic data acquired for site surveys?
J. Oukili, J.P. Gruffeille, C. Otterbein and B. Loidl
Journal name: First Break
Issue: Vol 37, No 8, August 2019 pp. 49 - 54
Special topic: Legacy Data
Info: Article, PDF ( 699.33Kb )
Price: € 30
After a prospect has been evaluated and the decision is made to drill, the well planning and design phase can begin. We must define not only the best location to enter the target reservoir, but also choose the right surface location to place the drilling rig and the wellhead, without forgetting the well trajectory between the wellhead and the reservoir entry point. In Norway, as in many countries, drilling operations are subjected to a well integrity in drilling and well operations hazard assessment in our case: NORSOK D-010, August 2004. The results of this assessment, in the form of a report, are submitted to the local authorities in order to get the approval to operate. This can be a lengthy process, between four and nine months, and possibly longer in the case of operations in a high-pressure high-temperature regime. The Norwegian Petroleum Directorate (NPD) guidelines are not prescriptive, and leave the operator to decide what is necessary to operate with the lowest practical risk. A site survey is commonly acquired to assist in the safe installation and operation of a drilling rig, and aims to: • Provide information on seabed and sub-seabed conditions to ensure the safe, secure and efficient installation and operation of a drilling rig, • Identify any potential drilling hazards in the shallow section, ideally down to the first kilometer, • Assess the location of potentially important seabed habitats, and • Provide an environmental baseline survey (EBS). An exemp-tion is possible if such a survey was done in the previous three years. The first two points are usually achieved by acquiring dedicated high-resolution (HR) 2D or 3D seismic surveys, and mapping the mud floor to get an ultra-high-resolution (UHR) image by side-scan sonar or multi-beam echo-sounder technologies. It is worth noting that the NORSOK D-010 regulation does not specify whether 2D HR seismic or 3D seismic is required. The charac-teristics of the seafloor itself are assessed using geotechnical methods such as a cone penetration test (CPT). For cost and time reasons, the dedicated seismic data is often acquired as a grid of 2D lines around the planned surface location of the well, and typically covers a small area of 2x2 km or 3x3 km (Figure 1). This implies that the location of the well is essentially final before conducting the site survey, which in principle, should confirm it. If the well, and therefore the drilling rig, had to be moved by a substantial distance and ended up being close to the limits of the newly acquired seismic data, a new survey might be necessary. Although rare, such risks exist, with all the implications for the project in term of delays and costs. It is possible to achieve great results with 3D HR acquisi-tion. However, the costs are considerably higher than for the 2D case and are difficult to justify to the asset managers unless the reservoir is shallow and can be imaged with the same dataset, in which case it would be a fit-for-purpose and efficient solution. This is not the situation on the data used for this project, where the main target from the Upper Jurassic level is at approximate-ly 4000 m depth. HR seismic surveys, designed to image the shallow section, are normally acquired with shallow-towed sources and receivers, usually towed around two metres below the sea surface. This makes the weather conditions a key factor for the success of such marine operations. In the North Sea the acquisition window is limited in time (April to October) due to the prevaling sea state. Outside this time window and towards the end of the season, the field operations are often affected by considerable downtime, increasing the project costs and also potentially jeopardizing the drilling operations altogether. Moreover, in parts of the North Sea that are prone to local fishing activities, a ban on seismic acquisi-tion can be imposed in what should be the most favourable period for shallow-tow HR seismic, typically from mid-July to September. What if we could perform the seismic part of the site survey investigations in the comfort of an office? What if we could cover an area 10 to 20 times larger than the one of a 2D HR seismic survey, but with a full 3D perspective and at a lower cost? What if we could do this site survey at any time we want or need? Having such a solution at hand would have the following advantages: • More time available for the well trajectory design, • The same shallow hazard survey (SHAZ) data could be used for any subsequent wells over the whole licence or prospect without the need for another HR seismic acquisition, thus reducing the overall field development costs, • No direct dependency on weather conditions or seismic activi-ty ban for getting the high-resolution data, • Potentially more vessels of opportunity to run the environ-mental base survey (EBS) and geotechnical work seismic vessels are specifically designed for seismic acquisition, • The extent of the reprocessing area can easily be adjusted. It would increase the size of the project, with some implications on costs (computation time up to 250 Hz), but have little impact on the turnaround time, • Apply the shallow hazard reprocessing over all areas covered by 3D conventional data, or large parts of it, as long as the required input data is available, • Initiate consultation with contractors for the EBS (if required) and geotechnical work to secure the boat and the crews at the beginning of the season, and • File for work permit with authorities sooner without waiting for the HR data interpretation (after acquisition and process-ing). That is why we started looking into dedicated high-resolution processing workflows, with a strong focus on the imaging of the shallow section that is under-sampled in conventional 3D seismic acquisition used for exploration or field development. The geometry of a conventional acquisition spread does not provide seismic recordings at very near offsets. The nominal minimum near offset is typically in the order of 110 m. In practice, the minimum near offset for imaging is much larger due to the crossline offset on the outer streamers. We believe that multi-dimensional data reconstruction cannot provide the information that has not been recorded in this offset range. We have seen in recent years more and more efforts from the industry to use additional data that could fill the zero-offset gap, the multiples. The seismic data we have been working with on our PL817 licence (Figure 2) was acquired with multisensor technol-ogy (Carlson et al., 2007) that has been the basis of imaging with multiples for a few years now (Whitmore et al., 2010). Reassured by previous examples, albeit in a different geological context, we thought that imaging with multiples combined with an adapted high-resolution workflow would produce final images that would meet the requirements of a site survey. The licence partners correspondingly agreed to launch the project.