A more accurate view of downhole fracture conditions can be determined from the log provided using PropTrac H.

Radioactive tracers are the most common method currently used to determine propped fracture geometry, but they present many safety and environmental issues that can have a major impact when using this technology as part of a fracturing treatment. Tracers must be transported, stored, handled, injected, and monitored in accordance with a number of state, federal, and international regulations.

Since the tracer is added externally as part of the proppant slurry, questions arise concerning whether the tracer has dispersed evenly within the propped fracture. Uneven distribution can lead to inaccurate interpretation of the actual proppant location. Both of these issues make radioactive tracers a less than desirable option with many operating companies.

A new option

Hexion has developed and field-tested an alternative, non-radioactive approach to determining propped fracture geometry.

PropTrac H does not use radioactive tracer materials, which means that the environmental and safety precautions, permits, and regulatory compliance required for the traditional approach are not necessary. This new environmentally safer technique provides more accurate information than ever before and can be easily used for any hydraulically fractured well.

The new technology uses proppants with a built-in tagging material in the resin coating. The coated proppants can be transported and applied just like conventional proppants. Since the tag is in each individual proppant grain, it is distributed evenly in the proppant pack and provides much more accurate information on proppant location in the fracture.

This innovation provides detailed data that allows operators to make more informed decisions about the perforating and fracturing strategy used for their wells. Now operators can design fracturing treatments to optimize results and increase production.

PropTrac H at work

Once the proppant is pumped into the well, a gamma spectroscopy logging tool is used together with a fast neutron source to temporarily activate the tag in the proppant. The tag then emits characteristic gamma rays that are visible to the tool’s spectrometer.

The logging tool detects the presence of proppants as well as the intensity of the response, which is proportional to the amount of tagged proppant in the fracture. This also provides insight into the width of the propped fracture. In addition, the tool has a gamma ray detector that records the natural background readings from the formation.

The special tag used in the proppant coating is unique because of its short half-life. Response levels quickly fade after the tag is irradiated. Tagged proppants are no longer active by the time the logging tool is pulled from the well.

Another major benefit is that logs can be run as often as desired during the life of the well without timing restraints because the tag only responds when it is stimulated by the tool.

This new method provides operators with valuable information that can be used to improve their designs or make well completion adjustments needed to create better wells.

The logs run are an extensive source of detailed data that assist engineers in calibrating frac design models. Modifications based on these data can be made to future stimulation treatment designs to achieve improved results.

Technology at work

An operator in East Texas used the new technology to identify the integrity of boundary layers during the fracturing of a well. The first fracturing stage, which took place in the Taylor Sand zone, consisted of a 30,000 lb tail-in of pre-cured resin-coated 40/70 mesh sand containing the non-radioactive tag.

The Taylor Sand had 20 ft (6 m) of 0.32-in. diameter perforations and was the deepest producing interval. Below the Taylor Sand was a shale barrier; above was the Lower Cotton Valley producing interval. That interval contained four sets of perforations grouped in 5-ft (1.5 m) intervals and covered approximately 230 ft (70 m).

The Taylor Sand was fracture-treated with a waterfrac that used 150,000 lb of 40/70 frac sand with a tail-in of 30,000 lb of 40/70 tagged proppant. A chemical tracer was used with this treatment to provide additional information to assist in verifying the log results. The operator decided to run the log 24 days after the Taylor Sand treatment.

Log information showed that the shale lying beneath the Taylor Sand stopped the fracture from extending below the lower boundary of the targeted interval. The Taylor Sand treatment also created a fracture that grew well beyond the upper boundary of the targeted interval and resulted in the presence of tagged proppant in a large part of the Lower Cotton Valley. The chemical tracer was in the water being produced back from the Lower Cotton Valley. The treatment on that interval did not contain the chemical tracer, so its detection was most likely the result of the extension of the Taylor Sand fracturing treatment into the Lower Cotton Valley formation. Since the chemical tracer was detected in the water produced from the Lower Cotton Valley, it was seen as verification of the results from the fracture height log.

The operator gained significant knowledge from the log about the downhole conditions. The data obtained gave a much clearer picture that explained the post-treatment results. This information resulted in the operator’s decision to change the fracture design from a high-rate waterfrac to a lower rate gel frac to limit upward fracture growth.

This not only increased production, but the information gained allowed much more informed decisions about how to improve fracture treatments on the offset wells.

Another successful field application took place in the Rocky Mountains. An operator wanted to improve the fracturing strategy, but there were regulatory restrictions in place that severely limited the use of radioactive tracers.

The operator was looking for a way to obtain fracture diagnostics information on the wells and discovered that the new technology had the capabilities needed without creating any environmental concerns.

The operator fractured the well with 88,000 lb of 40/70 tagged proppant and then waited 28 days before logging the well and gathering the data.

The proppant concentrations shown in the log indicate that two main sand zones were fractured in this well. Also, several shallower thin sand intervals displayed adequate to good proppant placement patterns. In contrast, the main sand zones in an offset well had fracturing problems and scant proppant responses. Because variations in hydrocarbon rates from production logs often compare well with contrasts in tagged proppant indication patterns, the zones needing additional fracturing could be identified easily.

The fact that the operator waited almost a full month to run the log did not have an effect on the ability to accurately detect the tagged proppant.

The operator redesigned its fracturing and perforating strategies, which led to an increase in production rates, directly increasing bottom-line revenue. Video available at https://www.epmag.com/video/ item7039.php