First Break - Volume 33, Issue 11, 2015

The advent and integration of new technologies in seismic acquisition, processing and reservoir characterization are allowing for a better understanding of the geologic processes playing a part in the creation of hydrocarbon reservoirs in the subsurface. Extended seismic bandwidths provided by broadband acquisitions (BroadSeis), improved illumination from wide-azimuth (WAZ) configurations and high spatial resolution made possible by dense acquisition techniques are all new technologies producing visually compelling imaging and reservoir results. In addition, application of the latest reservoir characterization tools and workflows on these data are bringing greater insight into the inner workings of petroleum reservoirs.

Towed streamer electromagnetic (EM) data acquired at the Mariner heavy oilfield in the UK sector of the North Sea have been inverted using a fast and efficient 3D anisotropic inversion code. The towed streamer EM system was towed from a single vessel. The system consisted of a horizontal bipole source and electrode sensors housed in a streamer cable. This enabled a densely sampled grid of data over the subsurface volume of interest. The purpose was to estimate the resistivity structure in a volume including the Maureen and Heimdal reservoir structures in the Mariner complex. The 3D inversion algorithm is based on the contraction integral equation method and utilizes a re-weighted regularized conjugate gradient technique to minimize an objective functional (e.g., Zhdanov et al., 2014). A moving sensitivity domain approach is introduced to handle the large amount of data over the large area (Zhdanov, 2010; Zhdanov and Cox, 2012; Zhdanov et al., 2014; Cox and Zhdanov, 2014). This inversion method is proven to be fast and efficient and is here shown to be suitable for towed streamer EM data from complex geological environments such as the Mariner area. In this case, the final 3D resistivity cube after inversion and with a corresponding normalized misfit of 5.4% correlates well with the expected structure from seismic data and well logs. In particular, the 3D inversion was able to extract an anomaly with vertical and horizontal resistivities of 8-10 and 4-5 Ohm-m, respectively, corresponding to the Maureen and Heimdal reservoirs close to the resistive chalk and basement. The run time on a PC cluster was only seven hours for the full 3D inversion with data from all survey lines covering the area of interest.

Offshore Seismic Permanent Reservoir Monitoring (commonly known as PRM) is a seabed-based technology that is becoming part of the reservoir engineer’s toolkit for practising better management of oil and gas fields. In its most commonly practised form, PRM involves conducting 3D seismic surveys at repeatable periods, generally somewhere between six months and two years. The time interval between surveys may be variable, and depends on the specifics of the reservoir being monitored. It has been demonstrated to be a technical success because, as fluids are injected and/or produced from a field, the seismic data change in response to the changes in the reservoir. The field implementation of PRM has now become a major geoscience and engineering activity yielding tangible results. This paper is an attempt to present an overview, facts, and opinions that will be of use to engineers and geoscientists who are interested in what has been done, and what may be done, in the use of seismic permanent reservoir monitoring, or oilfield surveillance. The PRM market appears to be on an upswing, but it remains to be seen if that upswing continues. There are several reasons that have tempered the adoption of this technology. One is that it has been difficult to determine and publicize the cost-effectiveness of PRM. While upfront costs are relatively large compared to many geological and geophysical activities, they are not large when compared to overall field development, optimization, and maintenance costs. Companies are now taking a more realistic look at the ultimate value derived from PRM due to the growing number of published benefits versus cost. The second moderating reason emphasized here is the number of stakeholders, with a wide variety of technical expertise, perspectives, objectives, and motivations, which must be involved in approving and executing such a project. This situation is being addressed as more corporate leaders are made aware of how PRM may address, in addition to production and operational needs, a number of health, safety, and environmental (HSE) concerns, broadening the interested constituent base within operating companies, and further establishing the benefits of PRM. There are currently 13 installed PRM projects, with the longest-running (Valhall) having been operating since 2003. The high-quality seismic data obtained from these projects are capable of showing very small changes in seismic amplitude and/or travel time that result from changes in the reservoir and its contents, such as fluid type, saturation, and pressure. The seismic systems themselves have also become the vehicle to integrate other measurements at the seafloor, such as temperature, water chemistry, or small changes in seafloor topography – all parameters that may have HSE implications. The growing importance of this oilfield surveillance approach will ultimately result in a variety of engineers collaborating not only with geoscientists, but also with other departments within the corporation such as quality control and HSE. As shown by the technical and economic successes of at least two projects (Valhall and BC10), the appropriate use of a PRM system significantly increases recovery, production rates, and operational efficiency, and reduces reservoir management costs (Chen et al., 2015; Barkved, 2012; Caldwell, 2009).

It is increasingly common for seismic surveys to take place among busy and complex operating fields. The variety and intricacy of simultaneous operations (SIMOPS) considerations have increased dramatically as oilfields and their infrastructure have developed. The implications of these disruptions range from unnecessary delays and downtime to a compromising of data quality. These effects are both undesirable and costly, prolonging surveys and increasing HSE exposure. Seismic acquisition is a challenge for the operators in the field and for the seismic contractor acquiring the data. Installations in a field may include platforms, drill rigs and floating production storage and offloading (FPSO) vessels with associated supply and standby vessels (Figure 1). All have ongoing operations with stringent schedules – diving, remotely operated vehicle (ROV) work, site surveys, drilling, and tanker operations. When a seismic vessel with towed streamers is additionally operating in the field, the SIMOPS complexity increases and careful planning is required. Communication of all planned infield activities is key to avoiding downtime and unnecessary disruptions. Typically, communication takes place between offshore personnel via email, phone and radio. Planned operations and exclusion zones are exchanged. In very active fields, a SIMOPS representative may be in place to compile the operations schedules every 12-24 hours, often in a spreadsheet or Gantt chart, then email this to the involved parties. The problems associated with the timing and the delivery method are obvious – by the time the email is sent, the information may be out of date, and a spreadsheet cannot clearly represent the spatial nature of the operations. To optimize the execution of critical activities, a SIMOPS management system must provide all relevant parties with timely, near real-time updates during rapidly changing operations. We describe in this article a SIMOPS management software solution that provides both a spatial and temporal overview of all known activities in the area in near real time, allowing a safe and efficient seismic operation.

The launch of the dual-sensor towed streamer technology in 2007 is seen by many in the industry as the most important milestone in marine seismic technology in the last decade. The introduction of the technology triggered a significant interest and demand for broader bandwidth seismic data and increased the industry-wide awareness of the geophysical benefits of such broadband data for both frontier exploration and production monitoring in mature basins. It also resulted in the rapid development of new acquisition and processing technology, both concerning the source and receiver side, as well as changes to seismic vessel design and equipment. The geophysical benefits of broadband data and the availability of up- and down-going wavefields as part of the dual-sensor deghosting methodology are now routinely exploited throughout the entire seismic value chain, including seismic imaging and reservoir characterization. After the first 2D dual-sensor survey in 2007, which was quickly followed by the first 3D acquisition commencing on New Year’s Eve 2008, PGS has steadily converted its seismic fleet from hydrophone-only to dual-sensor streamers. The pace of the technology roll-out has been largely driven by the life-cycle of existing streamer inventory and the equipment needs for newly launched seismic vessels as part of an ongoing fleet renewal process. The fleet-wide roll-out of dual-sensor technology will finally be completed in the 4th quarter of 2015 with the upgrade of the last Ramform vessel. Given the scale and complexity of replacing and industrializing a complete acquisition platform, there have naturally been significant lessons, some of which we will be sharing in this article. We will also discuss some of the acquisition and processing technologies that have been developed and/or adapted in order to fully utilise this new marine seismic technology platform.

With the recent Zaedyus-1 well oil discovery in French Guiana and the recent oil discoveries in the offset conjugate margin area in Africa (Sierra Leone-Liberia), it is no surprise that explorers are looking to continue this success into the Foz do Amazonas Basin of Brazil. Foz do Amazonas is the most northerly of the Brazilian equatorial margin basins with an area of 282,909 km², and water depths ranging from 50 m to greater than 3000 m. In this under-explored frontier basin, exploration drilling has been confined to the shelf, with 95 exploration wells drilled and ten of these with hydrocarbon shows. The 11th Exploration Licence Round focused on the potentially large reservoirs in distal Late Cretaceous/Palaeogene deep-water turbidite plays, following successful wells drilled in French Guiana. There are strong indicators for the presence of hydrocarbon-bearing reservoirs shown in recent publications, based on newly available data (Rodriguez et al., 2014). This study complements some of the evidence previously presented by analysing the prospectivity within the Foz do Amazonas Basin. We use temperature gradients obtained from exploration wells and Ocean Drilling Programme (ODP) wells, as well as values calculated from the Bottom Simulating Reflector (BSR) to model the geothermal gradient and present-day source rock maturity.

The scientific method and hydrocarbon propensity The scientific method is perhaps humanity’s greatest achievement, laying the foundation for the industrial revolution which, for some, improved living standards to unimaginable levels. It led to the harnessing of fossil fuels providing far more energy than a single person ever had at their disposal before, increasing prosperity in the process. There are direct relationships between per capita CO2 output and standard of living indices such as child mortality/life expectancy, and available funds for environmental protection. Almost every social advancement has relied on electricity generated with the fossil fuels our profession helps to locate and, despite costly drives towards renewables, 87% of world energy in 2013 still came from hydrocarbons. For 150 years there have been claims that fossil fuels have peaked. William Jevons in the 1860s forecast that Britain would quickly run out of coal, leading him to conclude that the country’s ‘present happy progressive condition’ would be of limited duration. But largely thanks to geoscientists, we enjoy ongoing supplies enabling affluence to expand. Despite demonisation by environmentalists, civilisation will depend on hydrocarbons for most of our foreseeable power needs permitting us to continue escaping Malthusian limitations. Imagine a world where Jevons was right and we had run out of hydrocarbons during the reign of Queen Victoria. Would standards of living have gone on increasing and how would the environment have suffered?

The Upper Morrow sandstone reservoir in the western Anadarko Basin is a major oil-producing reservoir. These sandstones have plagued operators and investigators alike because of their irregular distribution. It is difficult to detect these thin, discontinuous reservoir sandstones using P-wave datasets because of insufficient acoustic impedance contrast between the Morrow sandstone and surrounding shale. But the contrast in rigidity between the Morrow sandstone and surrounding shale causes a strong seismic expression on the shear wave data. Morrow sandstone reservoir is a good example to show how S-wave data can help to improve the detection of reservoirs with low acoustic impedance contrast. The P, SV and SH stacks obtained after processing multi-component seismic data are interpreted. The SV and SH stacks are from S-wave data obtained from horizontal source and horizontal receiver recording. The attributes extracted from the P, SV and SH stacks are correlated with the Morrow A sandstone thickness obtained from well logs. The SV- and SH-wave attributes give better prediction of Morrow A sandstone thickness compared to P-wave attributes. The multi-attribute analysis provides better correlation with sandstone thickness compared to a single attribute. The multi-attribute map was used to predict seismic-guided isopach map using cokriging.