Martin Bett, Senior Vice President Reservoir Solutions, TGS, UK
Martin Bett, Senior Vice President Reservoir Solutions at TGS, speaks about the role that Permanent Reservoir Monitoring techniques offered by TGS can play in helping to de-risk mature assets for operators in the North Sea.
In 2011, TGS acquired Stingray Geophysical. What does this do for TGS?
Acquiring Stingray to deliver Permanent Reservoir Monitoring (PRM) Solutions does two things for TGS: firstly, it allows TGS to satisfy demand for products in both the exploration and production seismic markets; secondly it delivers a predictable revenue stream over periods from two to twenty years, or more. In general, the oil and gas industry spends far more on production than exploration and production spend tends to be far more stable and consistent.
How is TGS promoting its permanent reservoir monitoring technologies through R&D; how is the business spearheading efforts to improve this science?
PRM systems deliver the highest quality seismic data which is necessary because one is looking for small production-induced changes in the reservoir. Placing seismic sensors permanently on the seabed provides the full azimuth, full wavefield data of the highest quality and best signal-to-noise ratio: the sensors don’t move, there is no flow noise and it provides four-component data including the acoustic pressure and shear wavefields.
Conventionally, a streamer is towed behind a ship for the purpose of obtaining seismic data. This is a noisy sensing environment, introduces repeat positioning errors and only acquires the pressure wavefield. Coupling sensors to the seabed and measuring the full wavefield allows us to differentiate between pressure and saturation effects as the reservoir is being produced.
Given that the lifespan of an oil field can be twenty, thirty or even 50 years or more, the technology used to instrument them must be reliable over such periods of time. Any PRM system is a significant investment and typically costs as much to install as it does to purchase. It should therefore be reliable as the cost of any intervention to repair or replace it will be high. TGS understands the need for consistent and reliable system performance over the life of the field and, for this reason, the Stingray technology is a passive fibre optic sensing system with no electronics in the sub-sea sensing system at all. Fibre-optic systems have been used extensively in the telecommunications industry for over twenty-five years now and are today what powers the internet we have become so reliant upon. Such optical systems and components have two characteristics that make them ideal for PRM applications: firstly they can transport very large quantities of data over long distances through a small number of fibres; secondly they are very reliable over a long periods of time.
As an illustration, the reliability of equipment is typically measured by what is known as ‘Mean Time Between Failure’ (MTBF). For electrical components, the unit used to measure MTBF is 1,000 hours. For fibre optic devices the equivalent MTBF unit is 100 years, several orders of magnitude longer. Using field proven optical fibres and components from the telecommunications industry reduces the risk of an expensive repair being necessary – a characteristic that is particularly important as we move into deep water, where the cost of installation or an intervention is even greater..
To what extent are you able to reduce the ‘spread of scenarios’ that a client is faced with when further developing a field?
Reservoir models are typically used to predict the behaviour of reservoirs. The one thing we know for certain about any reservoir model is that it is wrong! The model is developed based on information available at the time and usually when the reservoir is in a static condition. Once it is put into production the reservoir changes: wells are drilled, fluids are produced, fluids are injected; pressures and saturations change; geomechanical changes occur. It is hardly surprising that the modelled behaviour will, at some point, deviate from what we observe. The availability of frequent, high-fidelity reservoir images enables us to refine and enhance the model based on measurement instead of making changes to model parameters to closer align predicted and observed behaviour. Decisions made by measuring will clearly be better than those made simply by modelling. TGS’ Stingray system is available today, a technology which allows frequent, accurate updates of the model. This significantly reduces the spread of reservoir model scenarios and allows for better and more effective reservoir management.
What is the appetite you are perceiving for permanent reservoir monitoring (PRM) technologies at the moment?
The oil industry is notoriously slow to adopt new technologies, and this is no different with regard to PRM. The first system was installed in 2002 on the Valhall field in Norway by BP. This was followed by another system on Clair in the North Sea and a semi-permanent system in the Caspian Sea.
Before 2008 only BP had commissioned or installed a PRM system. There are now five major oil companies who have installed PRM systems: ConocoPhillips; Petrobras; Shell and Statoil in addition to BP. In addition, the amount of sensors commissioned and installed has doubled twice. The market is not yet mature but we are moving well along the technology or market adoption curve.
What is your internationalisation strategy for this technology?
TGS Reservoir Solutions operates in an international market. The sales cycle for PRM installations is a good two years, and the planning period for a company to undertake a PRM project is somewhere between two and ten years. We have been working with an increasing number of clients as they move through their planning stages and we see growing activity on a global scale in such areas as Brazil, the Gulf of Mexico, the UKCS and NCS, West Africa and the Far East. TGS serves these opportunities through its existing offices and where appropriate with local partners or representatives.
How does TGS’ experience here in the North Sea bolster its activity elsewhere?
Two characteristics of TGS are quite unique. TGS does not own any vessels, for carrying out 2D or 3D multi-client surveys; we use vessels provided by all the main seismic vessel contractors. This means that TGS can choose the right vessel and technology for any exploration challenge. In the future, I expect that this will also include seabed-based seismic exploration technologies, such as nodes and other techniques such as EM.
The second distinguishing feature is that TGS risks its own capital by investing speculatively in acquiring seismic and other geoscience data for the purpose of reselling this data to oil and gas companies as they search for new plays. We rely on our staff and their expertise to identify these opportunities and propose quality multi-client projects rather than being driven to keep expensive vessels utilised. This business model was originally developed and honed in the North Sea and the Gulf of Mexico. Growth for TGS has come from the need for increasingly higher quality measurements in mature basins such as the North Sea and from identifying attractive frontier regions such as Australia, West and East Africa and Greenland. TGS takes a global perspective in developing new projects and, in round numbers, invests half a billion dollars a year to acquire new multi-client data.
What does TGS envisage as the future of PRM and of its use by the oil and gas industry?
If one looks at the origin of the oil and gas business, it started with ‘wildcatters’, a well was drilled largely on intuition. Positive hits resulted in further drilling efforts nearby. Over the years, remote sensing techniques have been developed which allow us to image the subsurface and dramatically improve our ability to predict where oil is likely to be found, improving the hit rate in exploration activities. This increased use of data driven analytical techniques has improved exploration success rates and is now being applied to production activities as operators seek to maximise recovery from producing fields.
Measuring, not just modelling is key to this forward step. All reservoirs are heterogeneous; all reservoirs are more heterogeneous than originally thought; and the degree of heterogeneity increases as the reservoir is produced. The ability to frequently measure how the reservoir is evolving as it is produced is becoming a vital tool to optimise reservoir performance and reduce production risk. Historically, in a production environment, measurements were concentrated in or around the wells, but PRM provides crucial information about what is happening in the reservoir between the wells.
As a result, our customers want the highest quality data, more frequently, over the entire area of the reservoir. In the future, it is likely that most offshore oilfields will have some sort of PRM system installed, especially where production and well costs are high and poor reservoir management decisions will have a significant impact on the economic, environmental and technical success or failure of the project.
All the easy oil has been found; the industry is now left with technically challenging fields that commonly involve significant investment.
TGS’ Stingray technology is mature: it was derived from military applications which first evolved in the 1980s and 90s. Its application in oil and gas is now maturing rapidly: new fields are being developed from the outset with PRM monitoring systems in place to assure delivery of the base production case; investment in Improved Oil Recovery (IOR) techniques is growing and implementing PRM solutions reduces risk and guides decisions on new wells and other IOR activities. In the North Sea, PRM techniques can radically improve production efficiencies and deliver a further impetus to an industry dealing with the challenges of responsible and economic management of the UKCS’ oil and gas resources.