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Exa and BP - get relative permeability from a digital rock sample

Friday, May 4, 2018

Exa Corporation has developed software together with BP to model flows of multiple fluids through a digital image of a physical rock sample, and so find the relative permeability, a critical factor in understanding the reservoir.

Exa Corporation, a company based in Massachusetts, USA, has developed a way to simulate fluid flow through a digital image of a physical rock sample without losing any resolution, working together with BP. The technology is provided as an online software product called DigitalROCK.

The simulation solution was co-developed with BP, during a 3 year technology collaboration agreement.

It can be used to understand relative permeability - how multiple fluids flow through a reservoir, and the forces they will make on each other.

Exa claims that this is the first predictive computational solver for relative permeability for oil and gas.

Relative permeability is the resistance to flow for a mixture of fluids - for example a certain reservoir might allow water to flow through much more easily than oil. It is different to absolute permeability, which is the reservoir's overall resistance to flow.

The relative permeability can be used to understand what ultimate recovery can be achieved from the reservoir (a function of how much oil will be left behind in the pore spaces and never flow to a well). It can enable an understanding of how this can be changed with an enhanced oil recovery technique or water flood.

The basis of the study is a 3D CT (computerised tomography) scan of a small piece of core or drill cutting. Clients can take a scan image themselves, and upload it to Exa's online software, to run a simulation.

Exa is a simulation software company, specialising in computational fluid dynamics. It also serves the automotive, aerospace and aviation industries.

Exa provides purely software, provided over the cloud. You can upload a 3D CT image, and start running flow analysis, getting results 'in a relatively short time.'

BP agreement

Exa has been developing its flow simulation technology for a 'couple of decades', and realised it might be helpful when used together with pore scale imaging.

The company met BP in 2014, who were trying to solve the problem of relative permeability simulation. BP had done digital rock scanning, but not simulating multiphase flow.

In May 2017, Exa announced it had signed a multiyear "commercial agreement" with BP to provide its DigitalROCK relative permeability software.

BP said that the capability "will help engineering teams to make more informed decisions on wells, production facilities and resource progression, including enhanced oil recovery."

"The ability to generate reliable relative permeability information directly from digital scans on a much faster time-scale than laboratory testing, and to gain insight into the underlying pore-scale dynamics, provides substantial business value during appraisal, development, and management of our reservoirs," said Dr. Joanne Fredrich, upstream technology senior advisor at BP, in a press release quote.

"We plan to deploy this technology across our global portfolio. After a three-year program of cooperative development and testing, our extensive validation studies are drawing to a close."

Evolution of technology

Oil companies have been scanning rock samples in tomography scans and using the scan to model flow for about a decade now. The difference with Exa's technology is that it does not simplify the rock geometry at all for the modelling.

Other companies have made a model of pores from the scanned image, which can be good for analysing porosity, or single phase flow, but does not necessarily tell you how multiphase flow will travel through the rock, says David Freed, vice president oil and gas at Exa Corporation.

Flow in real oilfields is nearly always multiphase, Dr. Freed says, with oil and gas, oil and water, water and gas, or all three. Having just one fluid is 'extremely rare' (except if it is water).

Reservoir rocks nearly always begin filled with water filling their pore spaces, and hydrocarbons percolate in there over time and push the water out.

With Exa's software, the simulation is made without simplifications to make the computer model easier to compute. Its simulation technique uses the full geometry of the pore space.

In the simulation you can see oil and water moving within the pore space, and see how pockets of oil are getting trapped. There is a short video on website illustrating this.

The flow simulation takes into account the conditions which the reservoir is under, and how the results will change for different conditions.

Using the data

The data about relative permeability can be used as part of reservoir models, used for example to make decisions about where to place wells, and design enhanced oil recovery techniques.

Unless you understand the way different fluids behave then any predictions made by the simulators will not be very accurate. This includes simulations of how injection water will push oil out of the pores and increase recovery.

The data can be used to work out the end point - how much oil you will actually be able to produce from the reservoir, or in other words how much oil will stay in the pores at the point when no more oil is flowing to the oil wells.

The recovery factor of reservoirs varies greatly, from 20 per cent to 60 per cent, and this is the major factor in the return the company gets from the investment in building the oilfield.

The reason not all of the oil is produced is because some of it is left behind in the pores, trapped by capillary forces.

The data is also useful if the company is planning any water or CO2 flooding.

The water relative permeability also tells you how much water is being produced, something which operators also care about, because it is expensive producing and handling that water - and it also occupies topsides capacity.

And it is also important to be able to predict water production, so you can make sure your topsides capacity is able to handle it.

Oil companies are experimenting with surfactants (soaps) in injected water, which reduce the surface tension of the fluid mixture - so changing the flow conditions. With Exa's technology, you can get a sense of how a surfactant will change the hydrocarbon recovery, before you do it.

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