Why investors don’t believe our story Which data acquisition technology to use where Seabed seismic and James Bond How to use gravity with seismic Managing gravity and magnetic data at Statoil What you can do with fast computers Maintaining high resolution through to simulation Event Report, Transforming Subsurface Interpetation, June 10, 2015, Stavanger
Special report
Transforming Subsurface Interpretation
Event sponsored by:
June 10, 2015, Stavanger
Official publication of Finding Petroleum
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Transforming Subsurface Interpretation
Transforming subsurface interpretation, Stavanger, June 10, 2015
Finding Petroleum’s “Transforming Subsurface Interpretation” conference in Stavanger on June 10, 2015, looked at new ways technology can get a better understanding of the subsurface, including seabed seismic, gravity data, faster computers and high resolution modelling, and how to integrate all the data and manage it.
Conference chairman David Bamford, a non-executive director of Premier Oil, explained that the oil and gas industry is losing credibility from investors due to poor financial performance – not only because of the low oil price and high operations costs, but because of poor success rates in exploration in recent years.
There are many technologies which can help gather and integrate information, but working out how to get the best out of multiple subsurface technologies at once is very hard! This event was part of a series of 3 events, with events on the same topic also held in Aberdeen on March 12 and London on April 13.
Investors don’t believe our story Investors are getting very sceptical about the oil and gas industry’s ability to find oil and gas, said conference chairman David Bamford. Can better use of technology lead to more exploration success – and make us more investable?
Many oil and gas investors are starting to lose faith in the oil and gas industry’s ability to deliver with exploration, said conference chairman David Bamford, also a non-executive director of Premier Oil. “The viewpoint of all these investors is, we don’t believe a word that you say.”
“There’s a big issue of actual failure to deliver exploration results and reserves additions, to the point at which investors don’t believe our story. That’s a serious problem.”
This is in addition to concerns from low oil prices and high operating costs.
This means that the oil and gas industry does not look very attractive compared to other industries investors could put money into, he said.
That leads to the question of whether there can be better ways to understand the subsurface with the help of new technologies, to gather, integrate and manage data.
Mr Bamford suggests seabed seismic recording, fibre optics in wells, gravity and gravimetry, as technologies worth looking harder at. You have to choose the right technology for your project, and then, perhaps hardest of all, integrate all the data together at the end.
Seabed seismic
Seabed seismic is about recording seismic data on the seabed, rather than with recording devices towed behind a vessel on the surface of the water. You can get a much more high resolution recording if you make it on the seabed.
“The idea that you would replace towed streamer seismic with seabed based acquisition has been around for quite a while in the form of [seabed] cables,” he said.
“Universities in the UK and Norway have been using seabed acquisition for years and years and don’t understand why our industry doesn’t.” But “the operational difficulties has driven several companies out of business,” Mr Bamford said.
One seabed acquisition company “had such operational difficulties, it was having to repeat surveys at its own costs. It eventually disappeared in smoke.”
Companies are moving towards ‘nodes’ - individual devices placed temporarily on the seabed - which can prove cheaper to deploy than permanent cables. With seabed recording, you can acquire four component data (compressional waves and
three directions of shear waves). You can use this additional data to more sophisticated processing, including monitoring and mapping fractures. “The whole thing improves the chance of prediction [of oil],” he said. “This is a technology which has arrived and is finding widespread use.”
Almost all of the seabed surveys done so far have been done in the Gulf of Mexico, and have been “proprietary” surveys (where one oil company contracts the seismic contractor, rather than “multiclient” work, where the seismic contractor doing work which is then sold to many different companies). They are also mainly with nodes, rather than cables.
Fibre in wells
Meanwhile, the use of fibre optics in wells is making big steps forward, particularly the way that they can be used as listening devices, using technology mainly developed for the defence industry.
The cable is “so robust, usable and inexpensive you can deploy it in any well,” he said.
“It doesn’t interfere with production,” he said. As you can imagine, production engineers really hate any technology in wells which interrupts flow.
This special edition of Digital Energy Journal is an Event Report from our forum in Stavanger on June 10, 2015, "Transforming Subsurface Interpretation".
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Report written by Karl Jeffery, editor of Digital Energy Journal
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Digital Energy Journal - Special report, Transforming Subsurface Interpretation, June 10 2015
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Transforming Subsurface Interpretation “It delivers [continuous] recording of the noise the production is making, [plus] valves closing and shutting, anything going on in the well. So you can pinpoint where petroleum or water is flying into a well very accurately.
“You can use it for downhole seismic profiles [recording seismic data in the well] and record them any time you want. There is a possibility of permanent reservoir monitoring facility with some fibre optics downhole.” “So quite powerful stuff.”
The technology has been used to record seismic data in the well by one Middle East client, to monitor a multiwall steam injection in enhanced oil recovery, and recording Vibroseis shot data.
“There are obvious applications, but now really operationally sensible, because this stuff is so robust and works so well,” he said.
Gravity
Meanwhile gravity recording, or more specifically ‘Full Tensor Gravimetry’ (FTG), is “very effective,” he said. “Of all advances in technology, that one had the most impact on finding oil and gas.”
With FTG the gravity is recorded by two devices a short distance apart on the same aeroplane or ship, and then you make a comparison between their recorded signals.
The same noise (for example from aircraft movements up and down) can be recorded by two sensors, and by putting their signals together, the noise can be cancelled out. This means you end up with a much better signal
to noise ratio.
Mr Bamford got familiar with FTG in his previous role as a non-executive director of Tullow Oil, which was using the technology in Uganda and Kenya.
Choosing a technology
So which technologies should you use where?
For example, in a survey in North West Africa, with complex carbonate rock, “the critical technology to deploy is going to be ocean bottom nodes,” he said.
“In Uganda, we shot about 10,000 km2 of this Full Tensor Gravimetry. You could integrate it pretty well with 2D seismic, and you’d have a real exploration database you could explore with.”
For North West Europe, typically with sandstones and shale, “a combination of nodes and electromagnetics might be helpful to you.”
“It really is good at demonstrating the basin shape and showing you the structural pattern.”
“There’s been a reportedly quite large fractured basement discovery in the UK West of Shetland called Lancaster,” he said. “Allegedly this is part of a new play that could open up all the way from Ireland to Norwegian Sea.”
“In Kenya we acquired 60,000km2 of this gravity data. In somewhere like Kenya you can acquire tens of thousands of square kilometres relatively inexpensively, such as $23m dollars for the 60,000km2.”
Offshore, FTG is being used to help solve subsalt problems, which are proving hard to image using seismic only.
Another interesting non-seismic geophysics technology is Controlled Source Electromagnetics (CSEM). “Particularly in Norway, there’s been a lot of talk of the help that CSEM can provide to the exploration mapping process,” he said.
The challenge is working out how to fit EMGS data into your 3D seismic. “If you look at the equations involved and the rock parameters involved, it is not obvious how you join these things together,” he said.
“The key is first of all mapping where the edge of the basin is and what’s its history. [Here] Full Tensor Gravimetry (FTG) would be the important technology.”
The value of the reservoir depends on the distribution of the fractures, so these would need to be understood. “You can envisage some combination of the technologies I talked about earlier helping you,” he said.
Integration
The critical question which is not well answered is how to integrate all the data together.
The science and equations behind the technologies has been understood for over 100 years.
“But these sciences do not talk about the same thing. Some have first order differential equations, some have second order. That’s a complicated answer.” Most geophysicists’ IT set-ups are designed for interpreting 3D seismic. “The work processes that are built around them don’t easily allow the integration of other data,” he said.
“If you accept that these things will change and transform what we do, and therefore increase success rates, reserves extensions, appraising discoveries, making new discoveries, then somehow we need to figure out how to integrate these things,” he said. Watch a video of David’s talk and download slides at
www.findingpetroleum.com/video/1280.aspx
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Digital Energy Journal - Special report, Transforming Subsurface Interpretation, June 10 2015
Transforming Subsurface Interpretation
Seabed seismic and James Bond John Moses of Seabed Geosolutions explains seabed seismic using the analogy of James Bond trying to understand an object at the bottom of a murky swimming pool. Imagine James Bond trying to find an object at the bottom of a dark swimming pool.
He has an idea that something is there, and has a powerful torch to see it more clearly.
But he can’t work out exactly where it using the torchlight, because the torchlight bends as it goes through the water, and you don’t know the water depth or the amount the light is bending.
You can get a better idea by walking all around the swimming pool with your torch, and making calculations.
This analogy starts to indicate why recording seismic data on the seabed gives you a much clearer understanding of what is in the subsurface, said John Moses, regional sales director with Seabed Geosolutions, speaking at the Finding Petroleum forum in Stavanger on June 10, “Transforming Subsurface Interpretation”.
Seabed seismic recording can pick up more components of seismic data. Shear waves can’t travel through water, so recording on the water surface (as with towed streamer) you can only record compressional (P) waves. But on the seabed you can record both shear waves and P-waves. This multi component seismic data is analogous to having a more powerful torch to look in the swimming pool with.
Recording in different directions (azimuths) is expensive when recording with towed streamer, because it means making multiple trips with your source vessels and streamers. But when recording on the seabed, the recording device (node) can pick up seismic coming from many different directions at once. The multiazimuth is equivalent to walking around the swimming pool.
You may need to spend some more money on seabed seismic than towed streamer, equivalent to making more effort to understand the object in the swimming pool before you jump in. But drilling, like James Bond ruining his Tuxedo by jumping in the swimming pool, can only be done once.
There might be a sunbed floating on swimming pool, which makes it hard to the object. But recording seismic on seabed means that the obstructions on water surface don’t matter.
the see the the
Towed streamer seismic recording is not able to record near any obstructions on the water, such as offshore platforms (which are often built above reservoirs), as well as shallow water, rocks and ice.
Technology Seabed Geosolutions’ technology can do recording at very shallow depths and depths of up to 3000m, with nodes deployed in deepwater using Remote Operated Vehicles (ROVs).
The limit in the number of nodes in one survey is basically linked to the number of nodes you can physically deploy, and surveys are getting larger and larger. A typical offshore vessel in the North Sea can carry 10,000 nodes in containers, he said.
You can record with one node until the battery runs out. Battery capacity in nodes is increasing around 10 per cent a year, he said, and meanwhile the power consumption of the electronics is going down.
Seabed Geosolutions is a joint venture of CGG and Fugro.
Comparing the results In one example from the Dan Field in the Danish sector of the North Sea, a seismic streamer survey from 2012 was compared with a seabed survey conducted later.
The streamer survey seismic image shows a big gap in image resolution, from the area beneath an offshore platform where the vessel was not able to survey. When ocean bottom node data was recorded, there was no obstruction.
The subsurface has a chalk reservoir with a big fracture going through it. It has 108 wells, half producing and half injecting, with the wells producing and injecting changing all the time. In another example, data was recorded by Chevron, offshore West Africa in 400m water depth.
The company was using a streamer survey in an oilfield with a massive platform in the centre, and large water currents. “It’s a horror show for a streamer company,” he said.
Seabed Geosolutions flew 3 containers of nodes to the city of Pointe-Noire, and from there they were trucked to the town of Malongo, where they were loaded on the client’s ROV vessel. They were placed onto the seabed by ROV. “It takes 3-4 days to deploy and 3-4 days to pick them up,” he said.
In another example from an Australian field Apache used seabed data to provide a better interpretation of the oil water contact, which was very useful in the drilling program, Mr Moses said.
Drillers could get much more useful information from seismic data than they currently do, he said.
Another issue seabed seismic can help with is when there is gas in the overburden (the rock above the reservoir), which can block the passage of compressional (P) waves, which are the only waves towed streamer seismic can record. But with seabed recording, you can also record shear (S) waves, which can pass through the gas. This was a particular problem for a field in Malaysia operated by PETRONAS.
Digital Energy Journal - Special report, Transforming Subsurface Interpretation, June 10 2015
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Transforming Subsurface Interpretation
Geosoft – how to use gravity with seismic Geosoft has developed an effective modelling strategy for using gravity data together with seismic in subsalt interpretation.
There are many big oil and gas reservoirs beneath salt (including offshore Brazil), but oil and gas companies are often challenged when it comes to imaging the subsalt using seismic data only, because of the strong velocity contrast at the saltsediment interface.
Gaud Pouliquen, technical analyst with Geosoft, explained how you can use gravity data together with seismic data to get a better understanding of the subsurface.
As a starting point you can use seismic data to understand the rock above the salt, and use gravity to work out how thick the salt layer is (since salt has a lower density to the rock around it), and then use that together with your seismic data to understand the rock beneath.
To produce a model of the subsurface from the seismic data, you need to build a velocity model, in order to convert or migrate the seismic data from time to depth. Subsalt imaging often requires several iterations of migration and interpretation to produce a reliable velocity model and ultimately a subsurface model. To reduce the number of iterations in the velocity model building process, a 3D velocity model can be easily converted to a 3D density distribution, and gravity data can then be used to determine the base of the salt-sediment interface.
Traditionally, inverting gravity data to recover an interface or layer between two distinct density domains is done through a layered Earth approach where each domain is defined by relief surfaces. Within these layers, density is defined using a constant value or a density-depth function (e.g., to represent compaction). This type of approach has been used to invert on the base of salt. Although it is a fast method, it lacks the flexibility needed to account for complex geometry such as salt bodies (best represented by triangulated surfaces) and 3D density distributions.
Voxels An alternate approach to layered modelling is ‘voxel modelling’ where you split the subsurface up into millions of tiny cubes (the word ‘voxel’ is a join-up of ‘volume’ and ‘pixel’).
“It gives us far more flexibility in terms of representing complex geometry,” she said.
However the voxel based approach also has challenges to overcome: it is more demanding in terms of processing time, is limited by non-
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uniqueness (i.e., many different models can fit the data) and voxel-based inversions tend to produce smooth transitions between domains rather than a sharp interface.
Hybrid approach Geosoft has been working on a method which gets the best of both worlds (hybrid), called “Voxel Assisted Layered Earth Modelling” or VALEM.
VALEM introduces more flexibility to build the subsurface model. It allows for three different types of data structures within a single model: layers, voxels and 3D triangulated surfaces. The latter can describe complex salt bodies, while densities are described by a full 3D density voxel derived from the seismic model.
With the voxel based approach, it is also easier to add in other constraints, based on what you know about the geology, and therefore to address the challenge of non-uniqueness. And in order to sharpen the transition between the salt and the sediment densities during the inversion, VALEM uses an Iterative Reweighting Inversion (IRI) focusing technique. At the end of the gravity inversion you end up with a relief surface of the base of salt.
Base of salt inversion “Working out the position of base of salt is an important part of the seismic interpretation workflow,” Gaud said.
VALEM can be used to fine tune your velocity model or discriminate between different models, or you can let VALEM do the first attempt at working out the base of salt.
In that case the VALEM inversion is fed with a residualised density model where you can remove everything from the model that you know (e.g., what is above the top of salt). The inversion area is then constrained within the salt boundaries (i.e., you assume that you know the extent of the top of salt from the seismic).
Testing it
The process is to start with an initial velocity model which contains a top of salt but is "flooded" with sediment below the top salt.
Then you use this starting model to calculate what the gravity would look like if the model were correct, compare it to the observed gravity (i.e., the gravity anomaly generated by the true salt model), and calculate the difference or misfit between the two. You can send that difference to VALEM and invert for a base of salt that will minimize the misfit.
Then you can check how gravity computed from the model compares to actual gravity data and validate the recovered base of salt.
You might be slightly overestimating or underestimating the salt thickness in the deepest part of the salt body but there is essentially a very good match between the true model and the model recovered by VALEM. Looking at real world data, OMV tested VALEM using seismic and gravity data from offshore Africa, with water depth of 500 – 1200m.
“The seismic imaging was struggling with the salt and a high density in the crust”, she said. “Using this process, they recovered a plausible base of salt, and sent it back to the seismic team for validation.”
“For OMV it was a way to add value to the data at pretty low cost,” said Gaud. ”I should probably remind you that gravity field data is pretty cheap compared to seismic.”
“We’ve been testing VALEM with FTG (full tensor gravity) data. It’s not something we commercialize yet, but something to introduce in the future, alongside magnetic data inversion for subsalt,” she said. “Geosoft offers a service to run the computer processing in the cloud, via Microsoft Azure service,” she said. “So you don’t need your own high performance computer to run it.”
Watch a video of Gaud’s talk and download slides at
http://www.findingpetroleum.com/video/1333.aspx
The process was tested out using a synthetic salt model created by an SEG (Society of Exploration Geophysicists) research committee in 1996, designed to be a typical US Gulf coast salt structure.
Digital Energy Journal - Special report, Transforming Subsurface Interpretation, June 10 2015
Transforming Subsurface Interpretation
Managing gravity and magnetic data at Statoil Statoil has developed a centralised system for managing its gravity and magnetic data, which both specialists and generalists can use. Statoil geophysicist Christian Gram explained how it works.
Statoil implemented Geosoft’s DAP server solution for a centralised and organised system for gravity and magnetic data management, which both specialists and generalists can use. We want to “use all the data we Christian Gram have,” said Christian Gram, geophysicist with Statoil, speaking at the Finding Petroleum forum in Stavanger on June 10, “Transforming Subsurface Interpretation”.
“You have to be able to find [the data], know the value of it and know how to handle it.”
There are 200 potential users of the data, based around the world. The data is also used by GIS (geographical information system) users.
The company has about 3200 gravity and magnetic data sets, about 60 gigabytes of data. It also has many pdf reports, and data showing which areas have been surveyed.
The company uses satellite gravity data, which can provide structural information below the deepest interpreted seismic horizon, including calculating crustal thickness.
Statoil would like to use all available high resolution data for 3D forward modelling of complex salt structures. Another application of these high resolution data is the quality checking of velocity cubes/models. By forward calculating the gravity effect of a density cube (derived from a velocity cube) it can be compared with the observed high resolution gravity data.
Project background Before the project was implemented, the company basically relied on people’s memory to remember which areas were covered by data, Mr Gram said.
The Norwegian Geological Survey (NGU) had a system which enabled data sets to be downloaded, but “it never worked,” he said.
Statoil could use NGU system to find out file numbers, and then copy the data from its own system.
It was difficult to find metadata information, such as which projection system was used, Mr Gram said. The data was stored on a number of different drives. It was basically only available to specialists.
People were always asking if the gravity data existed, and then staff members had to search for it, which took up a lot of time.
With the growth in increase in gravity and magnetics, “the number of requests for data increased, and started to entrench on our specialist interpretation work,” he said.
People would discover data but not know if it was something new or a duplicate of something already known about, he said.
The data management project started in 2005 with a project to develop a clear system for publishing and archiving data, led by Mr Gramm and a colleague.
Using the system The data is available to all Geosoft or ArcGIS users, and available in a standard industry format for gravity and magnetic data.
You can search for the data by geographical co-ordinates, or by country, or both at once. You can also search using Geosoft’s “Oasis montaj” mapping system or ESRI ArcMap.
You can download the data directly into your projects. “You basically overlay it, in 2D view on your seismic as a pseudo horizon, at the right depths and the right scale,” he said.
All relevant information is entered via the Meta Data Editor when submitting files, such as data source, format, resolution, and projection. Further, if it is confidential, country, a short abstract, and data purpose. “If you leave
out data from the projection system the data set cannot be published, it forces you to do it properly,” he said.
The administrator can check the file properties and cell size. The administrator can also preview the data. The data is only ‘published’ once it has been checked by an administrator.
There is a server administration tool which makes it easier to archive and publish the data.
The system uses Geosoft’s “DAP” server solution. The datasets are managed using Microsoft’s SQL Server Management Studio Express. Statoil is also looking at integrating Geosoft’s “DAP” server further with ESRI data sets.
In future, the company might add electromagnetic data.
Statoil expects that its future explorationists should have a ‘minimum awareness’ of how to use and utilise gravity magnetics data, he said.
Watch a pdf of Christian’s talk at
http://www.findingpetroleum.com/event/8ea4d.aspx
Lenovo – what you can do with fast computers By changing microchips from CPUs to fast GPUs, in tests computers could run a standard subsurface workflow up to 31 times faster, Lenovo says. Computing hardware company Lenovo recently ran a test together with CGG to see how fast its computers could complete a standard task from the seismic interJohan Steffenson, pretation workflow, and saw Workstation Busi- an improvement of up to 31 ness Leader, Lenovo times, by using GPUs.
The computing challenge was “footprint removal”, removing a grid pattern which is often seen on seismic recording. The task required 12 iterations, and ran on a 610 MB data set. It was explained by Johan Steffensen, Nordic workstation Business Leader with Lenovo, speaking at the Finding Petroleum forum in
Stavanger on June 10, “Transforming Subsurface Interpretation.”
Different generations of workstations were compared doing the same computing task, to see how fast they were with previous 4 core CPUs inside vs the new 28 core CPU and technplogy and then comparing those towards different GPU's.
Digital Energy Journal - Special report, Transforming Subsurface Interpretation, June 10 2015
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Transforming Subsurface Interpretation The new CPU's performed up to 3 times faster and with GPUs it performed up to 31 times faster, he said. “You get a pretty good bump just on changing the CPUs.”
There was also an improvement in the input/output speed of up to 1.5 times.
Lenovo wanted to find out which hardware investments would provide the best return on investment in terms of making the processing faster, he said. “We tested a lot of components to see how they perform.”
The system has patented 3 fans cooling system, blowing cold air in separate chambers optimizing the cooling of CPU, GPU, HDD and memory. “This is basically the first solution that we made specifically for oil and gas and high end workstation usage,” he said.
If you are moving large data sets from the server room to your workstation computer, you can do it by moving the physical hard drive, he said.
Hard drives New workstation Following the research, Lenovo has worked out a configuration for its high end Lenovo ThinkStation computer, so it is optimised for us on oil and gas subsurface data.
The set-up is to have a P900 computer with 2x Intel Xeon E5-2697v3 processors, with 28 cores each, 256GB RAM, and optional a Magma EB3600-10 Expansion Chassis for adding more GPUs if you need it.
The system can have up to 1 terabytes of memory, and you can use a range of different storage devices.
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The role of hard drives is often underestimated as a component in the speed of the workstation as a whole, he said.
A study was also made on performance of hard drives, comparing time to download data sets from 2GB to 18GB. Hard drives compared included a USB3 memory stick, a standard PC 10k SATA drive, a 7.2k SATA, 10K SAS, SSD, M.2 and ioFX drives.
The M.2 drive can transfer data at more than twice the speed of a regular SSD drive, he said. “You will have some performance gains there, and the price is just above the SSD.”
Lenovo has made a spesific connector (Flex) for a M.2 drive so that it can be connected directly to the computer’s PCI bus, providing much additional speed, he said.
If you can connect multiple drives directly to the PCI bus you can get a much higher speed then if you have different hard drives connected to different controllers.
About Lenovo Lenovo was built from the former PC division of IBM, which was acquired in 2005. Previously it was a Beijing company called Legend.
Lenovo acquired IBM’s Intel based server business in 2014, and acquired mobile phone handset maker Motorola from Google in 2014.
In September 2014 the company launched a new platform for its workstations. The company works closely together with microchip manufacturer NVIDIA, and has a partnership with Microsoft.
Watch a video of Johan’s talk and download slides at
www.findingpetroleum.com/video/1325.aspx
Digital Energy Journal - Special report, Transforming Subsurface Interpretation, June 10 2015
Transforming Subsurface Interpretation
Schlumberger – model what you observe and simulate it When it comes to structural modelling, you can use your faults and horizons to work out how the subsurface was actually constructed, making sure the geological story works and defining your geological zones.
You can preview your structure in 2D (where it might be easier to work with), before getting into 3D.
You can use the Quantitative Interpretation workflow in Petrel to analyse the elastic parameters, and an example is to use the acoustic impedance data (how much the seismic data is blocked by the rock) to guide the porosity modeling, said Rania Carballares, Senior Geoscientist, Schlumberger Information Solutions.
The next stage is to build a structural framework model on Petrel, coming up with something which fits with all of your data, with the depth of geological layers matching the measurements made inside wells, with a robust geological model which can handle the complexity of the geology, she said.
All of the resolution gathered in your input data is preserved.
Reservoir simulation The next step is adding the fluid dynamics in the 3D reservoir model to get an understanding of how the fluid flows in the reservoir to make decisions on how to develop the field. Reservoir engineers generally have the mind-set to simplify (upscale) the reservoir model as much as possible to reduce the simulation time.
Dag Bakkejord, Senior Resevoir Engineer, Schlumberger
Sometimes this is valid due to the lack of information available and the characteristics of the reservoir. However, as the simplifications could lead to significant loss of geological detail and completely change the model characteristics, this destroys the hard work performed by other domains to describe the reservoir, said Dag Bakkejord, senior reservoir engineer with Schlumberger.
In addition, the fluid front is often not captured in course models due to the large numerical dispersion. This is critical, especially when investigating the effect of enhanced oil recovery (EOR) schemes.
INTERSECT enables the reservoir engineer to simulate the reservoir model at the resolution needed to capture the physics. The INTERSECT simulator quickly and accurately models not only conventional reservoirs but also handles complex structures, highly heterogeneous lithologies, and complicated wells and completion configurations. Detailed reservoir characterization, together with well and network coupling, can be honored with only minimal or no upscaling.
Unstructured gridding enables accurate and detailed modeling of the most challenging faults, fractures, and wells. Multisegment well capabilities accurately represent fluid behavior in horizontal wells and complex completions to improve both efficiency and accuracy in reservoir studies.
The INTERSECT simulator is available in the cloud for leveraging its power without having to build your own high-performance computing infrastructure. The subscription-based model scales with your business to give you models and data that are secure, access-controlled, and always available.
INTERSECT Schlumberger has been developing the “INTERSECT” high-resolution reservoir simulator since 2001 jointly with Chevron, with TOTAL joining the partnership in 2012.
Digital Energy Journal - Special report, Transforming Subsurface Interpretation, June 10 2015
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Transforming Subsurface Interpretation
List of attendees 'Transforming Sub-Surface Interpretation' at Norwegian Petroleum Stavanger Museum, Wednesday, June 10, 2015 Stephen Suttie, Senior Sales Executive, IHS
Ildiko Langaker, Survey Management, Baker Hughes
Johan Steffensen, Business Leader Workstation, Lenovo
Mille Nielsen, Survey Management, Baker Hughes
Gediminas Valantinas, Senior production engineer, Lotos Upstream
Kieran Parrett, Survey Management, Baker Hughes
Barbara Zarebska, Senior Reservoir Engineer, Lotos Upstream
Floris Doorenbos, Graduate Geologist, BG-Group
Ewa Pawlus, Geophysicist, PGNiG
Paul Mathias Fiskaaen, Director O&G, CGI Norway AS
Trond Bergoe, Chief Geologist, Envision as
Per-Ingar Auberg, Geoscience Advisor, First Geo
Erik Havarstein, Manager Geophysical Operations, Geograf Gaud Pouliquen, Technical analyst, Geosoft
Oystein Haaland, "WW Business Development Executive, C & P", IBM
Carl Ruben Ericson, IBM
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Cedric Nicou, Wireline Geophysics Domain Champion, Schlumberger
Linda Stuberg, Geophysicist, Schlumberger
Ricardo Colmenares, Technical Sales Manager, Schlumberger
Rania Carballares, Senior Geologist, Schlumberger
Dag Bakkejord, Senior Reservoir Engineer, Schlumberger
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Ole Evensen, Global Upostream BDE, IBM
Tyson Bridger, Commercial Strategy, IHS
Erik Monsen, Project Manager Innovation and Business Development, Prekubator TTO
Trine Kvist-Lassen, Geophysicist, Schlumberger
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Miriam Hohner, Petrophysicist, Schlumberger
Anne Oevreeide, Technical Manager, Schlumberger
Jorn Tore Paulsen, Account Manager, Schlumberger
Robyn Shaw, Geosolutions DP Supervisor, Schlumberger
John Moses, Seabed Geosolutions
Christian Gramm, Geophysicist, Statoil
Remi-Erempagamo Meindinyo, PhD Candidate, UiS
Yichen Yang, UiS
Thanusha Naidoo, PhD research fellow, University of Stavanger
Charlotte Botter, PhD candidate in Geosciences, University of Stavanger
Thanh Nguyen, University of Stavanger
Baard Elvik, Senior Drilling Engineer, Weatherford
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What did you enjoy most about the event?
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The introduction presentation that gave a little more than just the brief description on what's going on in the business.
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The opportunity to see what the industry is working on. Ricardo Colmenares Schlumberger
Everything worked well. Øystein Haaland IBM
Digital Energy Journal - Special report, Transforming Subsurface Interpretation, June 10 2015
The presentation on sea bed nodes with the James Bond analogy was excellent presented to a wide audience and kept the interest high.
