ROEC Interview Sep. 2015EN

Company: EMGS

Interviewee 1: Svein Ellingsrud, Founder & Technical Director Multi-client (Part 1)

Interviewee 2: Friedrich Roth, VP Imaging & Integration (Part 2)

Date: September 11, 2015

Topic: CSEM technology

EMGS: short company profile

The Norwegian company EMGS is one of the “original 3” owners of CSEM proprietary technology. Established in 2002 by Terje Eidesmo, Svein Ellingsrud and Ståle Johansen, the company was listed on the Oslo Stock Exchange in 2007. Based in Norway (Trondheim and Oslo) with regional offices in USA (Houston) and Malaysia (Kuala Lumpur), it has performed more than 700 surveys in frontier and mature basins across the world, in water depths between 30 and 3500 m. It has a diverse portfolio of clients, IOCs and NOCs alike.

PART 1:

Romania Energy Center (ROEC): O&G exploration techniques have evolved significantly over the past decade and a half. Why is 3D CSEM a breakthrough method for offshore exploration compared to the technology alternatives on the market? What is the main difference between classic 3D and 3D EM surveying?

Svein Ellingsrud (S.E.): When acquiring 3D CSEM data a grid of receivers (measuring the E and H fields) are dropped to the seafloor. The active CSEM source is then towed over each grid line while all receivers are active. In that way we get a full azimuth acquisition, “illuminating” the subsurface from many different angles. This was a similar breakthrough as going from 2D to 3D in seismic. CSEM is sensitive to vertical resistivity whereas MT is mostly sensitive to the horizontal. Towed 2D EM streamers are per definition 2D and can only be used in shallow water with electric dipoles. It is difficult with magnetic sensors. Wide azimuth 3D CSEM data also provides information about anisotropy. 3D seismic gives information about the geological structures, while 3D CSEM gives subsurface resistivity. The combination will therefore increase the chances for success in exploration. Look for resistive structures, not conductive!

ROEC: EMGS is one of the original 3 independent companies (alongside OHM and AGO) to start offering such commercial surveys in early 2000s. As someone who has been in this field from the very beginning, how would you characterize the market uptake of CSEM: successful but quiet, or rather, as a meteoric rise to the status of mainstream exploration technology?

S.E.: CSEM has been offered in the market now for approximately 13 years. In those 13 years both the equipment and processing software has changed a lot. 13 years ago basically only university hardware and university codes existed. EMGS uses today their 5^th generation receivers, with internal clocks that drift less than 1 ms per 24 hours. They are much more sensitive, we measure down into the piko-volt range, and they do not go into saturation when the source is passing over. That is used to get an almost exact rotation angle, which is important for azimuthal measurements. The source is built by Siemens, is extremely stable with controlled timing with GPS. Navigation is much better. All this is important for inversion because multiplicative and additive noise is reduced. Today, there exist full 3D inversion software. And most important, with stable clocks, we know there is a minimal phase drift due to instrumentation. All phase changes are caused by changed resistivity in the subsurface.

The adoption from different oil companies varies. Some big international companies are our best clients. And they have their own experts in CSEM doing their own inversions. In the Barents Sea, more than 50,000 km² of wide azimuth 3D data has been acquired and the Norwegian Petroleum Directory see it as positive to include CSEM data in the applications before the 23^rd concession round. So most companies accept that CSEM is working well in the Barents Sea.

Still, some oil companies are skeptical. The reason for some of them is experience with ambiguous “older” 2D CSEM data. Also, some of the older data had variable quality. Some wells were drilled and the interpretation was wrong. Or wells were drilled due to CSEM in the area, but the well position only picked by 3D seismic. The CSEM anomaly was NOT drilled, but CSEM “blamed”. One example is the Valkyrie well in the Norwegian Sea. Later 3D measurements show that the CSEM target was not drilled. And there exist false positives. SHELL and Statoil have published that they have 80% success rate when using 3D CSEM properly. PEMEX had around 90% success rate with their campaign of drilling wells based on the combination of 3D seismic and 3D CSEM.

ROEC: CSEM technology is credited with solving one of the ‘holy grails’ of O&G exploration (detecting oil without drilling expensive wells). As one of the founders of EMGS, could you tell us a little bit about the beginnings of this new service industry, in particular, about the research that lead to the establishment of EMGS and the first commercial application? What was the vision back then, what was the thinking 15-20 years ago?

S.E.: The founders of EMGS, employed at the Statoil R&D center, were working with petrophysics, well logs, rock physics and geophysics. Specifically, we looked at downhole EM equipment that could detect approaching water fronts in producing wells. During a meeting in Houston in 1997, we heard of an extremely strong magnetic source that could look several km down into the underground. That triggered the ideas of using EM from the seafloor. Statoil and the Norwegian Geotechnical Institute and later on, a small company called Mylab, did theoretical studies and modelling that showed that it was possible. We also realized that a thin resistor creates a guided wave that enables us to detect it from the seafloor. That was verified by laboratory measurements in a water tank. At that time, everybody said there are no waves done there, it is diffusion! Later theoretical publications show the phenomena can be described as guided waves.

And the vision was really that we had a technology that directly could detect hydrocarbons!

Later on, a sea trial was done offshore Angola in November 2000 over the Girasol field. Statoil arranged the trial and had the idea for the whole experiment. Both Scripps and the University of Southampton attend the cruise. Statoil took out a patent on the guided wave principle that is still valid after being challenged several times in court. Parallel with the R&D work, Statoil prepared commercialization of the technology and created EMGS in 2002. The first test was run over the Ormen Lange gas field in the Norwegian Sea and the very thin gas field was detected.

CSEM is detecting resistivity and is thus a DHI [Direct Hydrocarbon Indicator]. But keep in mind that also some lithology might have higher resistivity. Therefore the combination with seismic is important. OHM came out of the University of Southampton and AGO from the Scripps environment. So, almost all participants in the Angola cruise started companies. Western bought AGO and laid down the activity some years ago. EMGS acquired OHM around 2010.

ROEC: How did the industry’s interest towards CSEM evolve since the late 1990s? Do you see a correlation between the use of this exploration method and the price of oil? For instance, would you say that companies’ appetite towards using CSEM increases when the oil price is high and decreases when the oil price goes down? Or, would you say it has been rather constant and largely unrelated to the oil price level?

S.E.: We are facing the same downturn as the rest of the service business. However, a few companies now see that, using the combination of CSEM and seismic is a good way to reduce drilling costs. If you drill less dry wells, it is a great cost saving.

ROEC: It is our understanding that 3D CSEM is conducted on the seabed while traditional seismic on the sea surface. In your opinion, which one is less intrusive from an environmental point of view?

S.E.: I can only say something about CSEM. CSEM has been accepted by the environmental authorities in many countries. We have been 3 times in Canada which normally is pretty strict. The conclusion of the study there, is that there are no significant effects on the sea life or environment. The electric and magnetic fields from the source is much lower than the recommended levels for living organism or mammals on land. The only thing that is left on the seafloor is anchors that are made of dissolvable concrete. With only natural elements. So, only sediments are left after some months.

ROEC: Is there any known environmental impact associated with the use of CSEM technology on the marine ecosystem?

S.E.: No, not as far as I know.

ROEC: Has this exploration technology been used in the Black Sea? When and by which operators?

S.E.: Yes, CSEM has been applied in the Black Sea by Western Geco. I don’t remember the exact year, but it was around 2010. The Black Sea is a bit less conductive than normal seawater, so one has to evaluate to scale the transmitter electrode area.

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Part 2:

Romania Energy Center (ROEC): What kind of vessels do you use for 3D EM surveying? How big is your fleet? Do you own or lease these vessels?

Friedrich Roth (F.R.): EMGS has 3 EM survey vessels in operation. The vessels are leased and have been either purpose built or adapted for the safe and efficient performance of full-azimuth 3D EM surveys. Each vessel is equipped with 150 multi-component seabed EM receivers and 2 EM sources.

ROEC: Based on what factors do you decide how dense should a receiver grid be? How do you choose the appropriate spacing between the receivers, for instance why it should be 700 meters in one case and 3 km apart in another?

F.R.: 3D EM can be applied throughout the E&P cycle from early exploration through prospect evaluation to appraisal and development. Furthermore, economic considerations determine the target size of interest, which depends on water depth and is very different for frontier basins than for mature basins with existing production infrastructure in place. Therefore, surveys are designed to meet the specific survey objectives and provide the required resolution. This process is supported by 3D modeling studies and sometimes imaging tests to select suitable receiver/source towline spacing as well as optimal source waveform.

ROEC: Is the maximum current used by the source (1000 – 1250 A) a self-imposed (technology specific) or a regulatory limitation?

F.R.: EMGS has the strongest sources in the EM industry for the simple reason of seeing deeper and smaller targets. The most powerful EMGS source can emit a maximum electric current of 7200 Ampere. Such high currents however remain benign to the environment and marine life, and our R&D staff are working to increase source power further which is a non-trivial engineering task for subsea systems that operate in high pressure environments down to 3500 m water depth.

ROEC: How exactly does CSEM data integration with existing technology work? Can you describe this process? What are the stages of workflow?

F.R.: Although seismic is very good at mapping out potential reservoir and traps, many exploration wells fail because of high uncertainty in the seal and hydrocarbon charge of the prospect. Furthermore, there typically is high uncertainty in the hydrocarbon volume and discoveries are often found to be non-commercial. 3D EM is the perfect complement to seismic as it fills these information gaps by providing information about saturation (seal and charge) and being sensitive to the area and net pay.

The integration process typically consists of an interpretation stage and an evaluation stage, as is common practice in exploration.

During interpretation, EM anomalies are studied in terms of potential geological drivers. This is achieved through a process of co-visualization and correlation between the independent geophysical and geological attributes, classifying observations in terms of their potential lithological and/or fluid drivers, and confidence in these classifications.

The evaluation stage converts the observations made during the interpretation into risk and a volume probability distribution for the prospect. This includes assessments of EM data sensitivity and information quality, as well as quantifying potential interpretation pitfalls and correlation between EM and seismic direct hydrocarbon indicators (DHI).

Most oil companies wishing to use 3D EM face the difficulty that they lack the internal competency and tools to perform this integration work, stopping them from using 3D EM in their exploration decision making. Recognizing this fact, EMGS has developed evaluation software and workflows that facilitate this adoption, and we offer consultancy services to assist our clients in extracting the full value from 3D EM. This development has been met with enthusiasm by our clients, including majors, national oil companies or smaller independents.

ROEC: Both real and synthetic data are analyzed in the pre-drill stage and used as inputs for modelling. Can you explain what is considered real data and what – synthetic data?

F.R.: Real data is the measured data and forms the basis for all processing and interpretation work. Synthetic data refers to data that have been simulated for a specific geological or reservoir scenario. During interpretation, simulation may be used to help quantify the likelihood of a particular scenario or to establish the expected resolution to a structure of interest.

ROEC: The “anisotropic 3D CSEM inversion” seems to be an important part of the CSEM process. What is “3D anisotropic inversion”?

F.R.: EM data are imaged using anisotropic 3D inversion. This computational process converts the measured EM data into a three-dimensional resistivity model of the subsurface, which may then be interpreted. The process is computationally very intensive and is performed in our high performance computing facility in Norway. The term “anisotropic” refers to the fact that the resistivity of a rock depends on the direction in which an electrical current is applied. To get an accurate subsurface image, the inversion algorithm needs to account for the anisotropic rock behavior.

ROEC: In what cases can the interpretation of CSEM data be misleading? What are some potential traps to look out for during interpretation of CSEM results?

F.R.: 3D EM measures resistivity and not presence of hydrocarbons. During the interpretation process it is therefore important to consider whether any non-hydrocarbon resistors may also explain the EM observations. This is similar to evaluating interpretation pitfalls during seismic amplitude analysis. Examples of non-hydrocarbon resistors that may give rise to an EM anomaly are low porosity or cemented sands and carbonates. The good news is that very often it is possible to resolve any such ambiguity by integration with seismic attributes and geological knowledge, which is why integration is so important to EM interpretation.

Another common misconception is that the absence of an EM anomaly is evidence for the absence of a resistor and thus no hydrocarbons. Experienced EM interpreters know that absence of an EM anomaly merely indicates that there is no resistor with sufficient size and contrast to be detectable. Therefore sensitivity modeling, i.e. whether a target is detectable or not, is an important tool in EMGS’ evaluation software.

ROEC: Is CSEM strictly a marine method (offshore) or it can be adapted for onshore as well?

F.R.: In principle, CSEM may also be used for onshore exploration. However there are a number of practical reasons that make application onshore less attractive than offshore. The conductive seawater makes it easy to emit very high electric source currents and the ocean provides a filter for naturally occurring and cultural EM noise. This makes the marine environment ideal for acquiring very high quality EM data efficiently. Emitting a source current into soil is much more difficult and the same electrode coupling challenges occur on the receiver side when doing land EM measurements. Hence it takes significant effort to acquire good quality EM data onshore, which in turn makes it difficult to acquire large surveys in a cost effective way. Also the drilling cost onshore is lower, which impacts the value of information of EM data. For offshore exploration, the value of EM data can be tremendous.

ROEC: What is the main difference between CSEM and MTEM? Does EMGS offer both or only CSEM?

F.R.: EM methods can broadly be categorized into CSEM and MT methods. CSEM stands for Controlled-Source ElectroMagnetics. As the name suggests, this EM method uses an active source to excite electromagnetic fields that probe the subsurface and are measured on the earth’s surface. CSEM is used for mapping hydrocarbons. MT stands for MagnetoTellurics, which is a passive EM method exploiting naturally occurring electromagnetic fields that are generated in the earth’s ionosphere. MT can be used for structural applications such as imaging salt bodies and basalt layers. EMGS’ unique equipment can be used for both CSEM and MT measurements.

MTEM refers to a specific type of CSEM measurement, which was originally developed at the University of Edinburgh, Scotland. It stands for Multi-Transient ElectroMagnetics. The main characteristics of this CSEM measurement is that it uses a transient source pulse. EMGS in contrast uses a continuous source waveform that focuses the source power on a limited set of selected frequencies, typically 3-10 frequency peaks. Experience has shown that this provides better signal to noise ratio and allows for fast acquisition speeds of more than 4 knots. This is one of the reasons why the EMGS approach of acquiring CSEM data has seen the widest application and biggest commercial success.