6 Jun, 2017

Evaluating Fracture Stimulation

Every phase of development in shale plays requires an understanding of the fracture network created by hydraulic fracturing (stimulated reservoir volume). Knowing stimulated reservoir volume helps us estimate recoverable reserves, well spacing, and orientation. It also provides the basis for evaluating and improving stimulation practices.

 

Surface tiltmapping is a direct fracture diagnostic tool that measures and maps surface deformation caused by hydraulic fractures. The tiltmeter is a very sensitive device, similar to an electronic carpenter’s level, that can sense changes as little as one part per billion in the displacement gradient (or tilt).

Figure 1   Example of a tiltmeter. A modern tiltmeter uses a bubble level similar to a carpenter level.

The surface deformation reflects the azimuth(s) of a hydraulic fracture and the percent of treatment volume placed in each plane or orientation (when fracture growth occurs in multiple planes). Surface tilts are valuable in determining how fracturing volume is distributed – does the frac grow only at the toe or heel, or does it effectively cover the entire interval? The fracture orientation is the same as the observed “trough” seen at the surface. Surface tiltmapping provides direct measurement of fracture orientation while dimensions are measured by tiltmeters placed in offset wells or in the frac well itself. As formations being fraced get deeper, surface measurements may not be sensitive enough to accurately portrait frac geometry.

Microseismic mapping measures the location of micro-earthquakes or microseisms, resulting from hydraulic fracturing. These small slippages are detected by a vertical array of 12 or more geophones or accelerometers, placed in an offsetting wellbore (vertical or horizontal). After orienting each tool in the array (the perforating procedure in the well being treated is used to orient the three-component sensors), microseisms created by the fracture treatment are detected, oriented and located within the reservoir. As the treatment proceeds, a map of the event locations develops which provides time-based measurements of the fracture azimuth and dimensions. From Kevin Fisher, Figure 2 shows an example of a microseismic survey in a vertical well in the Barnett shale. The points represent discrete microseismic events detected by the geophone array and are located on the map in real time. This figure illustrates the complexity of fractures inshales. Notice the stimulated reservoir volume is large, about 900 feet wide and with a fracture half-length of more than 2,000 feet, for a total frac length from NE to SW of nearly a mile.

Figure 2   Note large stimulated reservoir volume created with a frac treatment in a vertical well. Frac fluid contacted the 5 “killed” wells during the treatment, providing direct evidence of the fracture network created.

Microseismic mapping is a great tool to identify stimulation effectiveness and opportunities for refracing or infill drilling.

Figure 3   Microseismic map illustrating stimulation effectiveness for 7 stimulation treatments with identified areas of additional potential.

The identified areas of opportunity must now be reviewed to insure these “holes” aren’t an artifact of observation well bias, lack of seismicity, acoustic attenuation or lack of a fracture network. These figures illustrate the value of microseismic in determining the number of wells to drill, well spacing and orientation. Using this type of mapping, the frac treatment can now be analyzed to determine the most important fracturing parameters that affect frac efficiency, and ultimately productivity.

In this example, it was determined that frac width and NW frac volume measured in surface tiltmapping predicted productivity. The correlation reflected cross-cutting natural fractures that were activated and dilated during the frac treatment. These natural fractures significantly impact well productivity.

In conventional tight gas reservoirs, fracture half-length correlates to improved production, however, in naturally fractured formations, this may not be true. Real-time microseismic fracture mapping allows fracture treatment designs to optimize. Treatment volumes, rates and perf locations for subsequent stages can be adjusted based on microseismic results to optimize the stimulated reservoir volume.

Figure 4   This example illustrates how the frac height is monitored; the microseismic confirms the created fracture did not frac out of the Barnett Formation.

Benefits of Microseismic Mapping

Figure 5

As an example, according to an article written by Digital News Group Hart Energy, new technologies such as fiber optics and augmented microdeformation technology are being used for microseismic sensing. In one case, an operator working with Halliburton in Utica used microseismic mapping coupled with fiber optics to create their stimulation model resulting in reduced well spacing and increase of 25% more reserves targeted.

Pressure Analysis

Treating pressure and post-fracturing pressure decline analysis are the most common methods of evaluating fracture treatments. Ideally, bottomhole pressures should be measured and used for these evaluations, but in most cases, surface pressures are recorded and used due to the lower cost and ease of acquiring the data. Be aware that significant errors can occur when using surface pressure data.

Bottomhole treating pressures can be measured with a dead string (run tubing, open ended and pump down either tubing or annulus; pressures measured at the surface on the static side, corrected for hydrostatic head, are a good measure of BHTP) or with bottomhole pressure gages.

The most important pressure obtained prior to fracturing is the closure pressure (minimum in-situ horizontal stress), the minimum pressure necessary to create a fracture. The closure pressure is also necessary to determine the net frac pressure during a minifrac and the frac stimulation, and to allow determination of the proppant strength required. Fracture pressure analysis is based on interpreting the “net fracturing pressure” (the BHTP – closure pressure). Closure pressure must be determined by fracturing the rock.

A pre-frac flow efficiency test (FET) can be used to determine closure pressure, fluid efficiency and fluid leak off properties (which can suggest reservoir quality when analyzed using the Nolte G function).

 

 

 

Conducting an FET:

Figure 6 is an example of an FET test. Pressures after shut in can be analyzed for closure pressure and time and qualitative reservoir properties using Nolte’s G-function plot.

Figure 6   Fluid Efficiency Test.

The plot of G[dp/dG] vs G is a very useful plot. Notice in Figure 7, when the fracture is open this plot is a straight line through the intercept. When the plot deviates from the straight line, the fracture has closed resulting in a change in the flow regime.

 

Figure 7   An example of a normal G-function plot.

 

 

In Figure 4, the Gc= 2.522 and  Ef = 2.522/(2+2.522) = 56%. As a qualitative indicator of reservoir quality, in normal pressured reservoirs – no geopressures, Ef greater than 75% would suggest the interval to be fracture treated and contribute little to production. 

Other shapes to the G[dp/dG] vs G plot can suggest unusual leakoff characteristics. In Figure 8, note the initial G[dp/dG] points plot above the early straight line. This behavior characteristic of pressure-dependent leak-off usually attributed to fissures or micro-cracks connected to the primary frac. Fracture treated intervals that show this property could have a high contribution to flow (micro-cracks adding to permeability) or could be poor contributors because of lower perm. Production logs will help understand the contribution these intervals will provide.

 

Figure 8   G[dp/dG] shows a hump above the straight line indicating pressure dependent leak-off. Baree & Assoc.

 

In Figure 9 G[dp/dG] initially lies under the straight line. This is characteristic of fracture height regression, perhaps from fracing up into a more ductile shale.

Figure 9   G[dp/dG] under the straight line indicates fracture height regression. Baree & Assoc.

Figure 10 shows the G[dp/dG] plot is a straight line, but doesn’t go through the origin and shows no closure. This would suggest a very low permeability zone and would infer little or no contribution to production.

 

Figure 10   G[dp/dG] plot does not go through the origin and shows no closure – formation is probably too tight to produce. Baree & Assoc.

These different curve shapes from the FET test can provide clues to what is pay and justifies a stimulation treatment, and what is not pay.

Some researchers (Conway, et. al., 2007) have developed a correlation relating initial post-fracture rate versus Gc, Figure 11. This would appear to be a useful effort in the resource plays to anticipate production from the many infill wells required to develop the play.

      

Figure 11   This is an example of correlating post-frac production performance to the “G”-function at closure. Baree & Assoc.

Another tool to evaluate the effectiveness of a fracture stimulation is a tracer survey. Tracer materials can be added to the frac fluid or coated on the proppant. By using different tracers with different frac stages, then monitoring frac flowback properties, an estimate can be made of which zones are contributing to production and which zones are not. Additionally, by running wireline surveys in the well, the tracer will indicate which zones were treated and whether the frac treatment stayed in zone.

Figure 12 is an example illustrating how the tracer survey showed in the well on the left (completed mostly in siliceous intervals) the frac was contained in zone, while the well on the right (completed in the clay rich intervals) showed poor frac containment.

Figure 12   An example where tracer surveys (red) showed the frac was well contained in Well M and poorly contained in Well A. LeCompte,B., et. al. (Reference 1).

Understanding the fracture network created by hydraulic fracturing (stimulated reservoir volume) is important in every phase of development of shale plays. Surface tiltmapping is a direct fracture diagnostic tool that measures and maps surface deformation, and provides direct measurement of fracture orientation. Microseismic mapping is utilized to measure the location of micro-earthquakes or microseisms, which result from hydraulic fracturing. Lastly, pressure analysis is important for evaluating fracture treatments. Knowing stimulated reservoir volume provides a measurement that enables estimation of recoverable reserves, well spacing, and orientation. It provides the basis for evaluating and improving stimulation practices.

For more information, see our Evaluating and Developing Shale Reservoirs course, or take a look at our other Unconventional Resources courses.


Sources:

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