Andrew McBarnet suggests that seismic permanent reservoir monitoring may soon be seeing a new wave of interest if not an increase in projects.
It seems like forever that people in the E&P business have been talking about a digital oilfield in which seismic permanent reservoir monitoring (PRM) would play an integral part. Ever since 3D time-lapse seismic, or 4D seismic, was shown to work, in the 1980s, the potential value of having seismic recording instruments placed on the seabed for the lifetime of a field seemed so logical as to be irresistible for optimal reservoir management. Once a system is installed, regular, more or less exactly repeatable, seismic surveys can be shot at the minimal cost of a vessel with an airgun and some instrumentation. The result should offer valuable images of the changes in a reservoir’s character as a result of hydrocarbon extraction, and provide data to determine the best oil and gas depletion strategy.
As we know, things haven’t turned out quite as expected. It is now 10 years since BP began operations with the first life- of-field seismic (LoFS) project on the Valhall field, off Norway. UK-based WGP Group has been carrying out two monitoring surveys each year, using a portable modular source system (PMSS) that it designed. Not so long ago, the company reported the 15th reshoot over Valhall. Over the years, there have been numerous testimonials from BP to the technical success and economic value of LoFS in helping to boost production from a field expected to continue until 2050. The apparent value of LoFS encouraged BP to undertake further PRM-type installations on the Clair field in the UK offshore sector and on the Azeri-Chirag-Gunashli (ACG) complex in the Caspian Sea.
Not surprisingly, the BP experience fueled an expectation in the E&P seismic community of new business. But PRM has attracted so few takers in the last decade that it could just as well stand for Phantom Reservoir Market. Excluding the BP fields, the tally for PRM projects, either announced or in service, amounts to Ekofisk in Norway (ConcoPhillips); Jubarte in Brazil (Petrobras); BC-10 in Brazil (Shell), Snorre, and Grane (Statoil). Not exactly a boom.
Oil-company pushback regarding the adoption of seismic PRM has either been on technical grounds, the value proposition or, whether such a system is appropriate or necessary. Whichever it is, the onus has fallen on the service sector to come up with a winning solution. As with much technology advance in the seismic business, oil companies have been able to sit back and wait to see what is on offer.
Ironically, the major marine seismic contractors have not fallen over themselves to win this particular technology race because it is not a great value proposition for them. Supplying equipment and installing a PRM system is a one-off project, while the margins to be made in equipment maintenance, reshoots, and even the regular data processing are not that enticing. There needs to be a stream of coming projects for the business to make commercial sense. It is perhaps symptomatic that Schlumberger, which was involved in the very first pioneering PRM system, on the Foinaven field west of Shetland in the late 1990s, has not been involved in advancing this technology. The company apparently does not regard it as a sustainable business. This has not stopped major geophysical companies such as Petroleum GeoServices (PGS), CGG, and TGS from investing in seismic PRM technology solutions.
Marine seismic contractors do understand the value of 4D seismic to offshore oilfield operators. Up to now, they have successfully persuaded the industry that towed-streamer, repeat 3D, high-resolution seismic surveys over a reservoir target can provide a satisfactory monitoring solution at a fraction of the cost and risk of a PRM survey installation, or even an ocean-bottom seismic survey using retrievable cables or nodes. The towed-streamer results cannot compete with the improved imaging from multi-component seismic recording on the seafloor. Only a few companies, with the financial capability and technical competence to make full use of that data, will order ocean bottom 4D, but they are very much in the minority.
But any type of 4D seismic can scarcely be called mainstream. For example, this year offshore UK and Norway, where the technology has seen most deployment, there will probably be a dozen 4D seismic surveys, mainly undertaken by the better-resourced oil companies. Worldwide, the technology is only gradually being adopted, and for many companies the value is too intangible to justify the risk and expense for stakeholders. They may also not have the technical resources to adequately deal with the data provided. It’s also true that the case for 4D seismic does not always exist for simple geological reasons, or scale, i.e., there are not enough reserves to work with.
Since the Valhall LoFS installation, the service sector has basically had to engage in a battle of persuasion with the oil companies over seismic PRM on two fronts, technical and cost. It has already been a long campaign with no obvious outcome.
A number of companies believed that they could improve on the buried seabed cable program adopted for Valhall, using the pioneering equipment supplied by OYO Geospace (renamed Geospace Technologies last November) that’s based on conventional, ocean bottom cable. Their goal was to answer the perceived industry concern over the longevity of the systems designed to last 25 years.. Three solutions, OptoWave (now part of the Fugro-CGG Seabed Solutions joint venture), OptoSeis (now part of PGS), and Stingray (now part of TGS) offered a fiber-optic based alternative. This is said to be more reliable and long lasting, principally because no in-sea electronics were involved and fiber-optic cable has a long-term track record in the transocean communications business.
The response to the fiber-optic option has been mixed as far as take-up is concerned. On the Petrobras Jubarte field off Brazil, PGS has recently completed the deployment of what is said to be world’s first full-solution, deep water, seismic PRM installationin water depths between 1200m and 1350m. The project makes use of OptoSeis, a fully fiber-optic sensor array installed on the seabed with opto-electronics on the topside of the FPSO P-57. The sensor array cables are laid out in two loops on the seabed with array cables placed 300m apart. There are sensor stations every 50m along the cables. A node with optical wet-mates enables the connection to the array loops. Riser cables from the FPSO and other lead-in cables help position the array where sensors are desired.
PGS will acquire seismic data once a year using a source vessel and passive seismic data twice a year. It will process the seismic data at its center in Rio de Janeiro. Early results are said to be promising.
Before the Fugro-CGG Seabed Solutions joint venture was initialled in February, CGG had conducted four monitor surveys on the Ekofisk field in 70m water depth. Its OptoWave fiber-optic system was installed for ConocoPhillips, covering an area of 60sq km with 200km of cable trenched at one-meter depth, containing 4000 four-component receivers. That service has now devolved to the joint venture.
Whatever the merits of the fiber-optic solution, Geospace Technologies has stayed in the game with its conventional ocean-bottom cable approach. Last year, it won a $14.9 million contract to provide over 100km of deepwater seabed seismic reservoir monitoring equipment for the BC-10 field off the coast of Brazil, operated by Shell. The system will be laid on the sea floor in 1700m water depth. The company followed this up later in the year through Statoil contracts worth $160 million for 660km of seabed seismic reservoir monitoring systems at the Snorre and Grane fields on the Norwegian continental shelf. Separately last month, CGG announced it had received the contract for long-term seismic imaging services for the project.
The choices of seismic PRM systems by different oil companies suggests that no technology has a clear lead. Indeed there is some feeling that Geospace Technologies is proving durable because, for the moment, it is the tried and tested supplier with a track record on all BP’s LoFS projects.
However, big questions still hang over current seismic-based PRM systems. None of the systems so far really address the issue raised most by oil companies, which is the value proposition. The high upfront capital cost is the main sticking point for several reasons. First, this plays havoc with the amortization of the field development costs. Second, there is risk. Companies can listen to suppliers’ assurances and look at projections based on modeling the future. However, most have clearly concluded that it is inherently unlikely that any equipment as sophisticated as the seismic recording cable involved will operate trouble-free for 25 or so years. In effect, only the well-resourced major can afford to take the risk. Third, it is often pointed out that oilfield development is conducted by asset teams focused on short term results, which they can report. Investing in long-term PRM does not fit into that category.
What we may be seeing now, is a move to answering the oil companies’ value proposition with more flexible solutions that present less risk and require lower capex. The impetus is a growing interest in ocean bottom seismic technology and economics and the emergence of new organizations. Among other things, this reflects an anticipated demand from oil companies for improved methods to image complex geological settings, deep water, and frontier environments, which is where much oil will be found in the future.
It is early yet, but the Fugro-led Seabed Solutions JV, which has emerged from the CGG purchase of Fugro’s geoscience division and was finalized earlier this year, brings together seabed seismic-node expertise from both companies, plus CGG’s ocean bottom cable and PRM experience. The formation of the JV alone suggests an expectation of growing opportunities.
A Norwegian company, Magseis, in which Anders Farestveit, legendary founder of Geco and Wavefield-Inseis, is the working chairman, has just won its first ocean-bottom cable contract for 200sq km of seismic for Statoil. Mike Scott, one of the founders of PGS and RXT, is also expected to join the fray with his new company, Seafloor Geophysical Solutions. The company promises ocean- bottom seismic to address enhanced oil recovery (EOR) and challenging deep-water exploration targets.
One of the most likely scenarios that could improve the economics and operation of seismic PRM is node development. ION Geophysical, which has in the past focused on its VectorSeis Ocean seabed cable solution, is known to be considering node operations; whether permanent or retrievable is unclear. Similarly, Geospace Technologies has introduced an ocean-bottom recorder for shallow and deepwater applications.
Fairfield Nodal may be the furthest along in using nodes for PRM. The company has already been operating the Z700 and Z3000 node systems, for shallow and deep water, respectively, in around the world, so it should be familiar with seabed seismic challenges. It is working on a system that can place and leave nodes on the seabed for extended periods of time, and therefore enable a number of monitor surveys to be shot with the nodes in the same location. The key is to preserve battery life by being able to turn the nodes on and off. The company also envisions an underwater optical communications system. Using ROVs, it is easy to see how nodes could be replaced or serviced while staying in position.
There is also a move toward offering more extensive monitoring. One example of this is Bergen-based Octio, in which Statoil became the major shareholder earlier this year. Octio’s ReM product line proposes an open architecture. The “Ethernet on the Seabed” infrastructure combines broadband reservoir monitoring for increased oil recovery with environmental monitoring and risk reduction during drilling and injection of fluid, gas, or waste.
With such a range of ocean-bottom seismic technology, active or in development, oil companies may soon be more open to the seismic PRM value proposition, but it’s not a given that this will translate into a rush of new orders.
PGS PRM project is in water depths between 1200 and 1350m, with sensor array cables laid out in two loops on the sea-bed of the Jubarte field. Array cables are placed 300m apart and have sensor stations every 50m along the cables. OE