Acquisition operations in progress over the Azeri-Chirag-Gunashli field complex in the Caspian Sea. (Photos courtesy of BP)

Since the invention of time-lapse (4-D) seismic, arguments have raged about how best to acquire it. Until recently, streamers have been relatively inexpensive and can be justified survey by survey, but it’s harder to ensure that the subsequent surveys are shot in exactly the same way as the baseline survey. Ocean-bottom cable surveys, although not used very often for 4-D purposes so far, hold promise for higher quality wide azimuth data but are much more expensive to deploy, at least at the outset.

BP decided to make the bold move of testing the potential for better data by using permanently installed cables over some of its largest and most complex developments. Dave Foster, BP’s global seismic surveillance deployment leader based in the E&P Technology Group’s Aberdeen office, argues that the higher up-front cost can potentially be more than compensated by the improved images that result and the ease; improved health, safety and environment (HSE) issues; and lower cost of shooting ongoing frequent surveys.

The first test

While the Valhall field in the southern part of the Norwegian North Sea was the first platform to get permanently installed sensors covering most of the field, a previous smaller-scale test case was done over part of the Foinaven field West of Shetlands. “What’s interesting about this one is that it was really, really early,” Foster said. “If you think about it, 4-D in general was invented and tested in the early ’90s. The Foinaven installation was deployed in 1995.”

BP was one of the early innovators of 4-D, working alone and also with Statoil. “We had done some 4-D studies with marine streamers,” Foster said. “We got an idea of what 4-D was and what it could do for us.”

It was not a high-tech venture. The company used regular marine streamer cables laid on the seafloor. But Foster said it was “a successful proof of concept.”

Valhall

The next step was to move from the proof-of-concept phase to a full permanent installation, and work was initiated to qualify a full-field system. The optional sites included Foinaven, but BP Norway’s Valhall was eventually chosen, with installation in 2003.

“It was driven by quite a few things,” Foster said. “Valhall is a large, complex field with imaging challenges. It was a good fit for putting a high-end seismic system in place to deliver good quality 3-D and frequent 4-D. But even then it was reasonably hard to justify as the first full system of its type.”

For one thing, instrumentation that could live on the seafloor for the life of the field simply didn’t exist. The company challenged the equipment manufacturers to devise a more purpose-built system comprising three geophones and a hydrophone for true multicomponent recording. Ultimately, GERI at OYO Geospace designed the system and has supplied the company with cables and recording equipment for its permanent installations ever since.

With the cables already on the seafloor, the ongoing acquisition activity is simplified. A modular seismic source system has been used on a platform supply vessel. This is a key part of the overall system for safe, efficient and lower-cost operations.

The main value proposition for permanent installation at Valhall is the ability to map waterflooding activities. “Monitoring injected water movement is a core activity in most 4-Ds because of the reservoir complexity and the amount of intervention that’s required to manage a waterflood,” Foster said. “You need to know where the water is going. That’s the surveillance component.

“Then you need to do something about it. That’s the intervention component.”

Since the installation, nine surveys have been acquired. Was it worth the cost? “It’s having a very significant impact on how they manage the field,” Foster said. “It’s improving flood management practices. To have seismic data every few months is a real eye-opener.”

He added that it’s not just the seismic interpreters who are interested in the data. Petroleum engineers have also taken notice and are using the information to make decisions about things like reperforating, acidizing, sidetracking and workovers. It’s also impacting the siting of new wells. Valhall has a difficult overburden, and the frequent data helps drillers drill new wells in the right places and in the right ways to avoid problems.

“The frequent data impacts different sets of activities, and it’s more in the time frame that the well engineers want to see,” he said. “These are really pleasing results. You’ve got a new data form, and it’s being used in a new way.”

One of the most important additional benefits is the ability to shoot multicomponent data, which images converted shear waves as well as compressional waves. At Valhall this is extremely important because of a large gas cloud in the center of the field. Compressional waves are severely distorted by this gas cloud, but converted waves are oblivious, enabling interpreters to better image the field.

Repeat surveys are also shot using wide-azimuth methodology, and Foster said this is nothing new — ocean-bottom cable surveys have routinely been acquired wide-azimuth for years. This has paid enormous dividends.

“For the right places, we’re getting wide-azimuth data that’s high-quality and enables us to make breakthroughs in imaging, not only in exploration but in production areas as well,” he said. “I think that’s a really captivating message.”

The main question at Valhall is how the frequent data will affect longer term reservoir management and ultimate recovery. “That’s the one we know the least about, even after a few years,” Foster said. “It’s on a longer time frame. But there are definitely observations that are coming out of the frequent 4-D that hold a lot of promise for calibrating the reservoir simulation models that will benefit reservoir management, hopefully leading to better forward prediction and management strategies.”

He added that the start-up of the waterflood was delayed, so the company is just now getting initial indications as to how well the seismic data is monitoring the process.

Remarkably, despite the newness of the technology, there were very few problems with Valhall. Foster said that the equipment was live when it was installed, meaning that problems could be detected and mitigated immediately. “Given the fact that it was the first one, it went extremely well,” he said. “BP Norway were doing a lot of firsts all at once with the project, so I think the fact that operationally it went as well as it did means it’s a big success.”

He added that up to 98% of the 10,000 receivers are still operational in the five years they’ve been in the ground, and the small amount of remedial work required was straightforward.

Valhall has been an education for BP, Foster said. “Life-of-Field Seismic is not ‘seismic as we know it,’” he said. “It’s part of an installation; it’s not a turn-key survey.

“The whole methodology is immature. We have faced installation issues when we’ve applied it in other places. It’s not a commodity yet. It requires bespoke installations everywhere we do it.”

But there are also major benefits. The frequency of the surveys has resulted in a processing and interpretation workflow that is well-understood. “Once you’ve got a workflow, you just crank the handle every time, and everybody gets the basic products within a very short period of time — typically days.”

Overall, he said, the most obvious success of Valhall is the fact that BP has since done two more installations and has plans for more. “That’s telling its own story,” he said. “We didn’t stop after Foinaven, and we didn’t stop after Valhall.”

Other installations

Since Valhall, BP has installed ocean-bottom cable instrumentation on part of the Clair field West of Shetlands in 2006 and on part of the Azeri-Chirag-Gunashli (ACG) field in the Caspian Sea in 2007, both as pilots for potentially larger installations. The ACG field system is unique in that, while the recording equipment is installed on the platform as for Valhall and Clair, the cables are movable and are deployed periodically around the fields as required, rather than being permanently entrenched in the seafloor.

Each field has its challenges. Clair has a hard, rocky seafloor, making it tougher to trench-in the cables. Ironically, the hard seabed is also the main cause of the poor-quality towed-streamer seismic that makes ocean-bottom data more favorable.

“It’s not the best 4-D territory for the rock response, nor is it the easiest territory for seismic acquisition,” he said. “The bold move was to say, right, with the high-quality trenched seabed cable system that we’ve got, we have a really good chance of seeing a 4-D response. It’s beyond the normal range of streamer capability to be able to see this.”

The ACG field is also expected to benefit from the multicomponent aspect of the seismic due to the presence of shallow gas and mud volcanoes.

Overall, the concept is showing immense promise. “With the first three BP systems installed and initial data still coming in, it is still relatively early days for this bold new technology. Hopefully, within a few years we’ll see other operators putting permanent OBC seismic in too,” Foster said. “And that’s to our benefit as well.”