Andrew McBarnet tries to fathom the future of permanent seismic reservoir monitoring projects.
A big pow-wow of industry specialists at the end of last month in Trondheim, Norway, was hoping to get to the bottom of the future prospects for using seismic surveying technology for permanent reservoir monitoring (PRM). The meeting was actually a long anticipated workshop organized by the European Association of Geoscientists & Engineers (EAGE) which was heavily over-booked. Although reports on the discussions may prove otherwise, the safest bet is that most people will leave as perplexed as when they arrived.
We are looking here at a technology which has actually delivered on its promise and yet continues to get a ‘good luck with that' response from all but a few companies, and of that tiny minority, only two or three have actually put some serious money down on the table.
The story to date is pretty well known. BP and Schlumberger in the mid-1990s began trialling the installation of permanent seismic recording cables on the seabed around the Foinaven field, west of Shetland, UK. The idea was that repeated imaging can track the movement of reservoir fluids, reveal bypassed oil, early intrusion of water, barriers to flow, etc. Detection of such features allows for more informed decisions on where to drill and how to plan production strategy.
The Foinaven pioneering project was sufficiently encouraging that in 2003 BP invested in its first life of field seismic (LoFS) development on the Valhall field offshore Norway. This was mainly designed to support a water injection programme and to improve recovery rates by optimizing the placement of production wells. The initial investment involved the burial over 45km2 of some 120km of seismic cable containing 2400 receiver units.
So far 12 monitoring surveys have been carried out, and many BP presentations over the last few years have testified to the technical success of the Valhall LoFS operation. Commercially the investment of around $50 million (which admittedly had some generous tax breaks) is projected to generate as much as $1 billion in extra revenue that BP might not have recovered without this and other measures to prolong the life of the field. The company has gone on to install a buried cable system over the West of Shetlands Clair field and a semipermanent system with moveable cables over the Azeri-Chirag-Gunashli (ACG) complex in the Caspian Sea, Azerbaijan.
BP's trail-blazing example with what seemed to be a convincing value proposition did not attract an immediate following by other companies. Indeed, a few years ago, BP itself had planned to implement a LoFS programme on the deepwater Holstein field in the Gulf of Mexico field as part of the initial development and not retrospectively as was the case with its other projects. But it never happened, apparently because of partner disagreement, and the company has not announced any further LoFS initiatives.
Plenty of explanations have been proffered as to why PRM remains mainly a hot topic for discussion rather than implementation. Basically it would be correct to say that it's all about the money, and we'll get to that. At first, the word was that oil companies would ‘wait and see' how Valhall went, but of course that couldn't last.
Technically, there did seem to be a good reason to hold off. PRM essentially offers the ultimate in repeatable 3D seismic (or 4D seismic) because the cables are always in the same position. In addition, cables connected to the seabed can use a combination of hydrophone and geophone receivers which provide multi-component data not possible from a streamer. Properly spaced, the cables also provide a wide-azimuth effect which allows imaging under complex geology such as the subsalt. Most of these advantages apply to ocean bottom seismic surveys using cables or nodes laid temporarily on the seabed, a method suitable for targeted reservoir locations. Historically, this approach has had limited appeal for the same reason that PRM has not garnered its share of enthusiasts.
What happened in the last decade was that marine seismic contractors convinced the industry that most of the benefits of repeatable reservoir monitoring surveys could be achieved with towed streamer acquisition technology, at the fraction of the cost of any ocean bottom seismic method. As a result, the vast majority of 4D seismic carried out to date has used towed streamers with a high degree of customer satisfaction. In this regard, proprietary higher resolution imaging improvements introduced by the leading players such as WesternGeco, CGGVeritas and Petroleum Geo-Services (PGS) plus the emergence of the steerable streamer have added to the claims for the accuracy and repeatability of towed streamer 4D seismic.
Oil companies have been encouraged to conclude that the more costly and, let's face it, more complicated multivessel ocean bottom seismic solution is unnecessary in most circumstances. It is usually justified to resolve some particularly complex geological imaging problem or to survey around offshore installations and other obstructions where towed streamers are inappropriate. Needless to say, it is of course in the interest of the marine seismic contracting community to continue perfecting the art of 4D seismic as monitoring surveys mean repeat business for its streamer vessels. Ocean bottom seismic is a specialty business with different equipment requirements much of which the main contractors decided to abandon some years ago as uneconomic to keep inhouse.
You could say, therefore, that there is some built in inertia regarding seabed seismic solutions on the part of both oil companies and contractors. This is well illustrated by the other big technical issue which has helped to cause prevarication regarding PRM in particular. Doubts, justified or not, have from the start been aired about the likely longevity of cable with electrical components operating in a subsea environment. There has been no suggestion that the cable recording equipment from OYO Geospace used by BP on its LoFS projects has been anything but reliable.
Even so, some bright sparks in Norway came up with the notion that fibre optic cable, which has no in-sea electronics, would be a better solution, and has a track record of several decades in the telecommunication ocean cable-laying business. For the last few years, the industry has become bogged down in a debate over the conflicting merits of conventional cable versus fibre optic which we do not need to rehearse in detail here. What we know is that the three biggest marine seismic contractors are hedging their bets. Through its purchase of Wavefield Inseis, CGGVeritas owns the Optowave system (developed in Norway), PGS has OptoSeis (developed in Norway), and WesternGeco has access to fibre optic through a strategic agreement with UK company Stingray which has evolved technology from the defence industry.
In the marketplace Statoil has experimented with fibre optic on the Snorre field, but ConocoPhillips and Petrobras are the only companies to have come forward with commercial PRM projects with fibre optic equipment. ConocoPhillips awarded a $40 millon plus contract to CGGVeritas/Optowave for a system to monitor the Ekofisk reservoir offshore Norway. It was installed last year but no word yet on performance. Meantime PGS with OptoSeis won the prized Jubarte PRM project offshore Brazil put out to tender by Petrobras. The contract awarded last year was worth upwards of $75 million with potential extras to come.
It is not at all clear whether these two fibre optic-based PRM projects have clinched the deal on the preferred technology, let alone given the green light to more widespread adoption of PRM. There is some speculation that one or two PRM projects of one sort or another could emerge this year, and that some feasibility studies could be tendered. But experience would suggest that any big change in momentum is unlikely.
PRM is a sophisticated seabed-based form of 4D seismic with multi-component data as a bonus. In the last decade three companies – Statoil, BP and Shell – have dominated demand for 4D which has been largely confined to the North Sea. It is now gaining momentum off West Africa and will probably be more prominent in the US Gulf of Mexico once things get back to a semblance of normality. The point is that if the customer base for 4D is limited, then even fewer companies will ever be interested in PRM.
It may be a positive that some oil companies, mainly the usual suspects and some other majors, are showing increasing interest in better resolution imaging of reservoirs through the deployment of ocean bottom seismic equipment, with individual node receivers rather than cable-based systems emerging as the popular option. This is probably not good news for the Norwegian company Reservoir Exploration Technology (RXT). It gambled some years ago on linking itself with ION Geophysical's VectorSeis Ocean cable-based solution to become the only marine geophysical company specializing in multi-component seafloor seismic data acquisition. RXT's pickings in the last year or two have been slim with little backlog to encourage anxious investors. In the North Sea this year much of the available, albeit limited, demand for ocean bottom seismic surveying has been won by US company Fairfield Nodal, which demonstrated its commitment to nodal seabed acquisition by recently changing its name from Fairfield Industries. In the North Sea Fairfield will be working for the likes of Statoil and ConocoPhillips as well as one smaller player Valiant Petroleum. It will use the DP2 vessel C-Pacer (with the capacity to deploy some 1800 of the company's Z700 nodes) and a shooting vessel New Venture. The company also has a continuing contract with Shell in the Gulf of Mexico for its deepwater Z3000 node acquisition technology.
Meantime WesternGeco, which has its own Q-Seabed cable-based OBC system, maintains a strategic agreement with Fairfield Nodal.
Fairfield's global rival is SeaBird Exploration, which is distinguished by its flagship vessel Hugin Explorer. The company can be said to have pioneered the use of retrievable nodes and has over time won contracts from Total and Chevron off West Africa, and BP in the Gulf of Mexico. It is due to operate for Chevron in the North Sea this summer on the Rosebank development.
The major development for SeaBird has been its recent strategic cooperation agreement with PGS to further develop ocean bottom node solutions for deep water. Jon Erik Reinhardsen, CEO of PGS, said the agreement would enable the two companies to provide a complete seismic offering in deep water areas, in areas with complex geology, and in areas with heavy infrastructure on the sea bottom.
The use of nodes for 3D, multicomponent and 4D seismic in deep waters to map challenging reservoirs is seen as particularly attractive in combination with PGS' broadband GeoStreamer and GeoSource technology. However, the real catalyst for the PGS move seems to be the company's booming business in Brazil, where Petrobras calls the shots and has the money and desire to explore all reservoir enhancement oil recovery options. PGS will have exclusive rights to offer SeaBird's autonomous seabed recording technology at market terms in Brazil.
CGGVeritas also has a nodal solution developed by its equipment division Sercel called Trilobit. It is described as being suitable for wide-azimuth seabed acquisition and an economical method for acquiring wide-azimuth data over small areas for targeted imaging of complex reservoirs.
Trilobit hasn't seen much action to date but CGGVeritas did win a significant multi-year ocean bottom cable (OBC) contract offshore Saudi Arabia, one of the few big OBC tenders. It is deploying its Sercel SeaRay OBC system for shallow water applications. One other company which is having success with shallow water OBC is Houston-based Geokinetics. It was the first company to deploy a SeaRay acquisition array. However, the bottom line is that OBC is not a business significant enough to divert the big players from their focus on towed streamer operations.
The current ocean bottom seismic status report would suggest that from a technical point of view the nodal solution is edging ahead of cable-based systems. There is some feeling that eventually this may actually further the cause of PRM. One challenge for PRM is that it is currently regarded as impractical and too expensive to instrument a reservoir covering a large area. One possible solution would be to combine a LoFS type set up over the most important producing target and supplement this with periodic node-based repeat surveys on the peripheral areas which would deliver nearly comparable high resolution imaging.
This may be some of the thinking behind Stingray's launch last month of two innovative mini-PRM products. Where a full 3D PRM is not appropriate, it is suggested that a smaller-scale fibre optic 2D PRM between wells could be a significant fluid monitoring tool for effective enhanced oil recovery. Similarly it proposes a passive seismic system for hydraulic fracture monitoring, again using fibre-optic cable.
As implied at the start, the fate of PRM rests more than anything on the value proposition. At the recent workshop one whole session was devoted to ‘Reducing the cost: permanent installations should cost no more than two wide-azimuth surveys'. That is a big ask and it does not really get to the heart of the financial issues. PRM proponents can argue that over the lifetime of a field the system pays off many times over, and – in principle – they are right. Once installed the acquisition cost of monitoring boils down to hiring a source vessel and data processing which is the same for any time-lapse survey. A towed streamer 4D seismic alternative is way more expensive and technically challenging.
But the crux of the matter is that the main cost of a PRM system is money – minimally $50-100 million – upfront with a very unpredictable, ie high risk, return on investment. No one knows whether PRM systems will last the predicated 25 years, no matter what the research projections suggest, and companies cannot be sure that they will get the reservoir enhancement results they expect. Also, who can guess where we will be with E&P technology in a quarter of a century? For example, 3D seismic was hardly invented 25 years ago. This type of thinking must give oil companies pause, especially when valid if not ideal alternatives exist. They can see that towed streamer seismic acquisition whether for 4D seismic or wide-azimuth continues to make huge advances, and temporary node or cable-based ocean bottom solutions are bound to improve over time.
Oil companies are notoriously shortterm in their thinking at the best of times which does not bode well for PRM investment. But you frequently hear the marine seismic community among others decry the asset team management of oil and gas developments focused on immediate results. As someone put it with regard to PRM: why would asset managers choose to invest in their successors', successors', successors' success? OE