Image FRAC^TM

How does this all work?

FracSCAN technology uses our pressure-based fracture map computed with our patented data acquisition1 and processing2. The data source is a surface pressure gauge on a monitor well—established through isolation from prior stages—that records the poroelastic pressure response from a nearby treatment well during hydraulic fracturing. As the treatment well is fracked, our geoscientists and completion engineers identify and quantify the poroelastic signals from the monitor well’s measured pressure response.

We use the poroelastic signals to compute a simple, accurate, affordable pressure-based fracture map by matching the observed responses in the monitor well to a digital twin. The fracture map includes fracture half-length, height, asymmetry, and azimuth and how fast these dimensions grew.

You can switch the treatment wells and monitor wells and continue completions, capturing the pressure responses from those fractures. The data acquired with this novel approach is a collection of pressure responses between monitor and treatment stages with the relative locations of each stage pair.

With FracSCAN technology, you can decide if or when you need to change the stimulation treatment—including stage length, cluster spacing, fluid volume, proppant size, and proppant volume—to match a development’s varying geology.

Customer Experience: Size them up

Is fracking with slickwater better than crosslinked gel?
What is the effect of total fluid volume on treatment efficiency?

An Eagle Ford operator asked us to analyze the effects of several completion design changes across several wells in south Texas. The operator varied some completion parameters—fluid type, fluid volume, proppant loading, number of clusters, and stage length—as fracking proceeded on the pads. Because the goal was to optimize these parameters for future completion designs, the operator needed to understand the fracture geometry and the geometry differences as a parameter was changed.

The growth rate of the largest fracture showed that the crosslinked gel produced more linear fractures with lower cluster efficiency compared with the slickwater treatment that generated higher fracture complexity and improved cluster efficiency. With FracSCAN technology, the operator made an informed, better decision about the right treatment design for the optimal fracture geometry, fracture complexity, and cluster efficiency.

How does this all work?

ProppantSCAN technology uses our pressure-based proppant mapSM computed with our patented data acquisition1 and processing2. The data source is a surface pressure gauge on a monitor well—established through isolation from prior stages—that records the poroelastic pressure response from a nearby treatment well during hydraulic fracturing. As the treatment well is fracked, our geoscientists and completion engineers identify and quantify the poroelastic signals from the monitor well’s measured pressure response post-treatment.

We use the poroelastic signals to generate a pressure versus time curve. Once the pumps are shut off and the treatment ends, the pressure begins to drop and eventually levels off. The initial drop in the pressure represents the fluid leakoff before the fracture begins to close onto any proppant embedded in the fluid and left behind in the fracture, also known as the proppant landing point. We use our proprietary digital twin and proppant-area solver to compute the minimum and maximum propped dimensions.

With the proppant map and ProppantSCAN technology, you can obtain an accurate estimate of the effective drainage volume.

Customer Experience: Not around the bend

What effect does well orientation have on propped fracture geometry?

Is minimum horizontal stress always the best wellbore orientation?

An operator working on two, four-well pads in the Eagle Ford called on us to analyze the effect of well orientation on propped fracture geometry. One set of wells was drilled in the direction of the minimum horizontal stress (SHmin) and the other set of wells was drilled at a 45° angle to the SHmin. Both pads had identical completion designs. We went to work with ProppantSCAN technology to find out which pad had the better-propped fracture geometry.

The technology showed that both pads had very similar hydraulic fracture half-lengths and heights. But, there was one significant difference. The propped fracture geometry of the wells drilled at a 45° angle to the SHmin was 50% smaller than the propped fracture geometry of the wells drilled in the same direction of the SHmin. This understanding is important from a proppant transport point of view for wells drilled at a 45° angle to the direction of the minimum horizontal stress. For these wells, fracture reorientation is likely to occur, limiting proppant transport because of the increased fracture complexity.

With ProppantSCAN technology and the greater insight into the propped fracture geometry from the proppant map, in addition to other datapoints, the operator made informed, better decisions about well spacing in the Eagle Ford.

How does this all work?

DiverterSCAN technology uses our pressure-based fracture map computed with our patented data acquisition1 and processing2. The data source is a surface pressure gauge on a monitor well—established through isolation from prior stages—that records the poroelastic pressure response from a nearby treatment well during hydraulic fracturing. As the treatment well is fracked, our geoscientists and completion engineers identify and quantify the poroelastic signals from the monitor well’s measured pressure response.

We use the poroelastic signals to compute a simple, accurate, affordable pressure-based fracture map by matching the observed responses in the monitor well to a digital twin. The fracture map includes fracture half-length, height, asymmetry, and azimuth and how fast these dimensions grew.

With the fracture map and DiverterSCAN technology, you can compare the largest fracture’s growth rate before and after a diverter drop so you can determine the success of a given design. A successful diversion results in stopping or impeding the fracture growth. Unsuccessful diversion results in the largest fracture continuing to grow post-diversion. By knowing these two scenarios, our customers have realized a 10% to 30% increase in production by quickly identifying the optimal diversion design to implement on subsequent pads.

Customer Experience: Two hours and done

Is relying on one diversion design the best way to work?

Can you evaluate multiple diversion designs quickly?

Before the operator began fracking the well, we worked with the completion engineers to develop a comprehensive data acquisition plan that accounted for the planned fracking sequence and any field operations constraints, such as a zipper fracking manifold and the reach of overhead cranes. The data acquisition plan was included in the field operating guidelines. A real-time data stream was set up to transmit pumping data— pressure, rate, and proppant concentration—and offset wellhead pressure to our office.

Once fracking concluded on a stage, a team of our geoscientists and completion engineers finished the data processing and quickly analyzed the individual diverter drops. The team immediately let the operator know whether the diversion stopped or had no effect on the largest fracture growth in that stage. We evaluated several diversion designs, identifying the design that provided the optimal diversion. With DiverterSCAN technology, the operator made an informed, better decision about the right diversion design.

“We’re applying Reveal Energy Services’ DiverterSCAN technology to optimize our completions in a new and quicker manner. Within two hours, we received an analysis that allowed us to evaluate the effectiveness of our diversion implementation while completing wells on one of our Stack/Scoop pads. With these quick results, we determined the most effective diversion design on the remaining stages instead of relying on one unverified design for the entire completion.” Byron Cottingham, P.E., Sr. Engineer for LINN Energy

How does this all work?

DepletionSCAN technology uses our pressure-based fracture map computed with our patented data acquisition1 and processing2. The data source is a surface pressure gauge on a monitor well—established through isolation from prior stages—that records the poroelastic pressure response from a nearby treatment well during hydraulic fracturing. As the treatment well is fracked, our geoscientists and completion engineers identify and quantify the poroelastic signals from the monitor well’s measured pressure response.

We use the poroelastic signals to compute a simple, accurate, affordable pressure-based fracture map by matching the observed responses in the monitor well to a digital twin. The fracture map includes fracture half-length, height, asymmetry, and azimuth and how fast these dimensions grew.

With the fracture map and DepletionSCAN technology, you will understand the challenges, such as asymmetric fracture growth and impaired stimulation when fracking near a depletion zone. The map shows in near-real time when a newly created fracture in the child well is affected by depletion around a parent well. You can take timely, corrective action that protects the parent well by minimizing or eliminating the effect of frac hits, in addition to improving the treatment effectiveness of the child well.

Customer Experience: Don’t waste a frac

What is the affect of a depleted zone on fracture asymmetry?

Does a depleted well in one horizon affect the fractures in another horizon?

A Bakken operator called on us to understand depletion zone effects on fracture growth and asymmetry. We computed a pressure-based fracture map with the fracture growth rates for the heel stages of the four wells. With the fracture map, we quantified in near-real time the interaction of newly created fractures with the existing depleted parent well in the upper horizon.

The depleted well caused significant asymmetry in the fracture growth. The asymmetry was observed on wells in both horizons. Wells 1H and 4H, in the same horizon as the depleted parent well, above, had slightly higher asymmetry while wells 2H and 3H, in the lower horizon, had less asymmetry.

Understanding the fracture growth timing and the degree of asymmetry offered insight into the extent of the depletion and the effects on the wells in both horizons. With DepletionSCAN technology, the operator made informed, better decisions about designing the treatment for upcoming stages.