Refracturing presents an economic alternative to drilling new wells.
Refracturing presents an economic alternative to drilling new wells.
There is, it seems, a constant refrain, in this post-oil-price-rout environment, about the survival of shale operators and, by extension, their suppliers. The immediate need is to cut costs across the board. Yet, even more important is the need to maintain—and even increase—production from existing assets. The decline curve in unconventional reservoirs is steep, a trend typically countered by the drilling and completion of new wells, which is both costly and time-consuming. At current oil and gas prices, in many cases, completing new wells does not provide the requisite Internal Rate of Return (IRR) to pass economic muster.
Enter refracturing. A few years after coming onstream, most horizontal shale wells produce at a fraction of their initial rates, leaving large volumes of unrecovered oil and gas in the rock. These bypassed reserves could be accessed through refracturing. While this is not a new technique, it is one that is being used more and more, because of the oil price decline. Vertical wells have been refractured since the mid-1990s, but with mixed results, earning it the nickname “pump and pray.” However, the industry’s understanding of fracturing and horizontal completions evolved during the shale boom to such an extent, that the techniques and technologies now available certainly can play a key role in the efficient application of refracturing in horizontal wells. In fact, according to conservative estimates as many as 75,000 wells in the U.S. could be candidates for a second wave of fracturing.
Refracturing provides a simpler, more logical and lower-cost alternative to drilling new wells. If output is declining in an oil or natural gas well, and fracturing the well provided sizeable production, then repeating the process, on the same well, should provide another boost to production and ultimate recovery. The likelihood of enhancing recovery is supported even further by the fact that many of the first- and second-generation unconventional wells were drilled with fewer stages, and with less proppant, than is commonplace today. With a higher density of perforation clusters and larger volumes of proppant used for refracturing, it is conceivable that these older wells would see a significant boost in production, at a much lower investment.
However, stimulating new rock by refracturing is not without its challenges, particularly for today’s long horizontal wells with multi-stage completions. Most refractures today are done without mechanical isolation, opening all stages and perforation clusters to fluid flow, thus posing several questions:
Which part, or parts, of the old well will benefit from refracturing?
Did the refracturing open new fractures, or just reopen existing, depleted fractures?
How can selected stages be isolated, and only those stages be refractured? What tools/techniques are available for mechanical isolation?
In the absence of mechanical isolation, are diverters working to isolate and move the refracturing down the well? Is the entire wellbore being restimulated or just portions of it?
How does the new stimulated rock volume (SRV) differ from the SRV achieved in the first stimulation? Does it really add to the original estimated ultimate recovery, or only provide a temporary boost in production?
These questions are fundamental to the decision to refracture. Refracturing opportunities range from remedial work—which fixes stages that were not completed properly or where proppant flowed back into the well—to enhancing recovery through the reenergizing of the fracture network, creating a new network for delivery of production-enhancing chemicals. In all cases, the success of the refracture will first need to be modeled, within the context of the specific project, and diagnosed, through the use of measurement techniques, such as microseismic monitoring. Successful implementation of just such refracturing programs will help us, as an industry, beat the decline.
The Barnett, Eagle Ford, Haynesville and Bakken are among the oldest of the shale plays, with large inventories of wells that have been on production for several years. Pilot refracturing programs have been underway in these plays; with operators becoming more adept at identifying high-quality refracturing candidate wells, and applying smart operating practices to enable successful refracturing. It is expected that wells in these plays will benefit the most from refracturing, since the oldest wells present opportunities to apply knowledge that came later in a play’s life, such as cluster spacing, impact of fluid type and proppant volumes. While refracturing, generally, results in increased production, one question remains unanswered: Is the refracturing creating new fractures, or is it reactivating old depleted fractures?
Microseismic data from original frac and subsequent refracturing.
Fig. 1. Microseismic data from original frac and subsequent refracturing.
To gain an understanding of where new rock is being stimulated, we need to look at an example, where surface microseismic data have been acquired during the original frac, as well as when the well was refractured, after several years of production. The two time-lapse data sets (Fig. 1) are very consistent, with similar spatial bias and uncertainty in the event positioning, allowing for direct, accurate comparison of the microseismic data from the two acquisitions.
The microseismic data acquired during the refracture determine several trends that correlate with the original microseismic data, suggesting re-activation of depleted fractures. Microseismic activity is also apparent in regions that did not demonstrate any such activity during the original frac, indicating the creation of new fractures. The results also indicate that, generally, the refracture azimuth is the same as the original frac, with limited evidence of fracture re-orientation during the refracturing. While studies suggest a possibility of fracture re-orientation during refracturing, it is typically a function of the time elapsed between the original fracturing and the refracture. It has also been observed that the longer the duration between the original fracture and refracture, the lower the possibility of fracture re-orientation. This is an important consideration when selecting candidates for refracturing. Changes in stress orientation can significantly alter the results and success of the refracture.
The case study represented in Fig. 1 had the advantage of the original hydraulic fracturing results to compare against. Hence, in addition to understanding the spatial and temporal distribution of the overall refracturing program, the microseismic information and associated completion evaluation provided real-time information about the portions of the program that contributed to the stimulation of new drainage areas. In most cases, however, microseismic technology was not used in the initial fracture stimulation for time-lapse determination, so those data are not available. Microseismic events that relate to stimulating new rock during a refracturing program can be differentiated by integrating the results with treatment pressure analysis, particularly net pressure and initial shut-in pressure (ISIP).
ISIP and microseismic events during the refracturing.
Fig. 2. ISIP and microseismic events during the refracturing.
Figure 2 shows a plot of the ISIP and microseismic events during the refracture. The x-axis shows the stage number during the refracture. The primary vertical axis on the left shows the ISIP computed for every stage. The solid red line shows the ISIP recorded during the original frac job, representing the virgin rock stress. The secondary vertical axis, on the right, shows the cumulative microseismic event count.
It takes several pumping cycles (stages) before we see any significant microseismic activity, Fig. 2. For these initial stages, the recorded ISIP is less than the ISIP recorded during the original frac. This indicates that the fluid and proppant volumes being pumped are working to overcome the depletion caused by production. Once the ISIP reaches or exceeds the ISIP of new rock, a significant increase in microseismic activity is apparent. Microseismic events recorded beyond this point most likely belong to new fractures being created. The information above is used to create a map of the depleted zones, using the location of microseismic events recorded while the ISIP is less than that of new rock.
To validate this observation, MicroSeismic, Inc. conducted a geomechanical analysis of the refracture, utilizing Istasca’s FLAC3D geotechnical modeling code. A geomechanical model was created to model a hydraulically fractured well with depleted fractures. An implicit discrete fracture network was described in the volume, based on regional knowledge and microseismic observations from nearby wells.
Geomechanical properties and rock failure criteria were established from offset well logs, the world stress map, microseismic focal mechanisms, DFIT and ISIP.
A refracture schedule ran for 50 hr, while pumping at a rate
Based on early success stories, as well as the sheer number of wells that would benefit from refracturing, it is expected that shale well refracturing activity in North America will increase steadily as companies optimize the process. There are, of course, risk factors that need to be taken into account, especially when refracturing older wells that may have completions that have been compromised over time. Also, not every well will respond to refracturing. Understanding the performance, and the critical factors that will ensure success, is key.