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Analysing fracs using a surface pressure gauge and bridge plug

Friday, May 11, 2018

Reveal Energy Services, a Houston company spun out from Statoil, has developed pressure-based fracture map technology to evaluate the frac half-length, height, and asymmetry. The technology is based on a pressure gauge and a bridge plug on a monitor well, and some clever data analytics.

Reveal Energy Services, a Houston company spun out from Statoil, has developed pressure-based fracture map technology to evaluate the frac half-length, height, and asymmetry. The technology is based on a pressure gauge and a bridge plug on a monitor well, and some clever data analytics. The technology was originally developed by Statoil.

Companies can confirm whether the stimulation treatment is producing the planned fracture dimensions to improve treatment design and well lateral spacing decisions. The system also provides insight into the fluid system so you can understand where the proppant goes, in addition to insight into the perforation clusters, diverter effectiveness, and depletion boundary.

The frac evaluation is equivalent to other methods of evaluating fracs, such as microseismic analysis, fibre optic monitoring and electromagnetic imaging, says Sudhendu Kashikar, CEO of Reveal Energy Services.

The company has done an analysis and comparison of this technology with other methods, using a variety of completion variables, including fluid design, proppant size, perforation designs and diverter types, he says.

With this method, it is possible to validate the completion design on every well you frac, not just a small sample. There is no disruption to operations, or large numbers of oilfield personnel

The technology has already been used in over 2,000 frac stages in the US and Canada.

The technology costs about 20 per cent of the costs of legacy diagnostic technologies, such as microseismic and electromagnetic frac monitoring systems, and even lower if larger volumes are involved.

How it works

The system works by using the stress effect that fracking a well has on a neighbouring well, which has already been fracked, and is full of fluid.

To explain it, we will call the well being fracked the 'treatment well' and a nearby well used for monitoring the 'monitor well'.

A pressure gauge is placed at the wellhead of the monitor well. The monitor well should only have one stage isolated and affected by the work on the treatment well. This is achieved by placing a bridge plug below the last stage fracked in the monitor well, isolating the fracs in the previous stages from the pressure gauge.

Then, when you create a new frac in the treatment well, the new frac creates a stress field in the rock around it, which leads to a pressure response in the monitor well. Over the short term, because everything is stable in the subsurface, the increase in pressure in the treatment well will lead to an immediate and visible response in the monitor well.

The bigger the new frac is, the higher the pressure response in the monitor well.

The clever part of it is how you use the pressure data to get fracture geometries, Mr Kashikar says.

Different sized and shaped fractures in the treatment well will drive a different response in the monitor well. For example, if the fracture is 600 feet long and 50 feet high, or 400 feet long and 100 feet high, the response in the monitor well will be different. The 3D stress field created by the two geometries listed above can be quite different and will result in a different pressure response.

The distance between the new frac and the observation frac is taken into consideration in the modelling.

For the system to work, the maximum distance between the treatment and monitor stage is around 1500 to 2500 feet (457m to 762m). The company is working on extending that range.

Other data

The technology has been further developed to provide information about how far the proppant has gone out into the rock and where it went.

The company can also do analysis of perforations so an operator can improve cluster spacing decisions with the highlighting of fluid distribution within a stage. The perforation technology offers a clear understanding of pumping rate effects on fluid distribution.

You can also look at other changes, for example, using hybrid gels to support proppant rather than slickwater (chemicals added to water).

You can also get data about the effectiveness of diverter (chemical or mechanical) agents used to make a temporary block in parts of the well and stop a 'runaway' fracture.

Reveal Energy Services' diverter technology can quickly analyse and determine if a given diverter drop has been successful in stopping the growth of this 'runaway' fracture. The studies show that sometimes diverters can actually make a problem worse, somehow accelerating the growth in the largest fracture.

Some clients use the data to test out different diversion techniques in the same well. 'They can get feedback in near real time on what technique did or didn't work,' he said. 'They can also try different materials or different quantity of materials.'

Data model

Behind the technology is a 3D stress model, which computes what kind of pressure response might be expected in the monitor well and how much a new fracture in the treatment well will increase the pressure in a facture in a monitoring well. The computer model then uses observations from multiple fracs and determines the geometries of the newly created fractures by comparing the predictions with the observations.

The system does not require any calibration and is insensitive to rock properties such as Young's Modulus and Poisson's Ratio. This is a result of the unique formulation and setup of the stress models.

The model is set up as a force balance problem, monitoring how the force being imposed on the treatment well is being balanced by an increase in pressure in the monitoring well.

'By setting this up as a force balance problem, the underlying problem becomes fairly insensitive to rock properties,' Mr Kashikar says. 'There's only one place the extra pressure can go, and that's into the monitoring well.'

Technology development

Statoil developed the technology after finding that none of the available techniques for understanding fracs were cost effective to deploy on a large number of wells, Mr Kashikar says. These older techniques also needed additional equipment and people on the wellsite.

This meant that the industry was typically monitoring fracs on a few pilot projects, and assumed the results were similar on all wells.

Statoil challenged its R+D team to come up with a technique which would allow them to monitor a much larger number of wells, so they could quality control the fracture geometry when they moved to 'factory' mode.

The research project started in 2015, with methods tested on actual wells in the Bakken and Marcellus, comparing results with microseismic and electromagnetic analysis.

The technology was spun out into Reveal Energy Services in mid-2016, and the company has continued to develop the technology. It has so far been used on over 2,000 frac stages, with between 20 and 90 frac stages on each well.

Many clients have undertaken cross validation studies, comparing the results from Reveal Energy Services with results from other methods, and 'so far, every study has shown that it is as accurate as any other method,' he says.

The pressure-based fracture maps have been generated from work in Canada and in the US in the Bakken; Permian Basin's Midland and Delaware Basins; Oklahoma's Woodford Shale; Eagle Ford; and Marcellus and with projects starting in Colorado.

Associated Companies
» Reveal Energy Services
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