In 1995, Advanced Resources International, Inc., began studying the North American restimulation market. One of the first orders of business was to enlist the services of Spears & Associates to complete a restimulation market survey. Two objectives were defined by Spears & Associates for the survey. First, producing and service companies were surveyed about well remediation activities, and second, restimulation activity was to be forecast through the year 2000. Spears conducted “almost 100″ interviews in person or by telephone across the different producing regions of North America. In the United States Rocky Mountain region, a total of 19 interviews wee completed with either managers or engineers from producing companies and with service company representatives.
The responses to five questions from the 1996 survey were particularly enlightening:
“In the last 12 months, how much emphasis has your company placed on remediation or restimulation of wells in this region?”
The survey reports “almost noe” as the current operator focus on restimulation in the Mesaverde formation. Frontier formation restimulation activity was reported as being “limited.”
“On average how much improvement results from this remedial work?”
One Mesaverde formation operator reported a 15% productivity and recovery improvement. Operators in the Frontier formation reported more success with remedial treatments. Production rate increases of 50% to 75% were reported.
“What reservoir or stimulation performance problem were you trying to solve?”
All Mesaverde operators surveyed reported that below expectations well productivity was the problem needing remediation. Frontier operators identified multiple problems, including productivity below expectations and problems during the original stimulation treatment.
“How do you determine if remediation is necessary?”
Only well production data was used to identify restimulation candidates.
“What technical barriers prevent more successful restimulation?”
Respondents producing Mesaverde formations replied that reservoir quality is the only technical barrier. Frontier formation producers identified proper stimulation technique and stimulation fluids as the technology barriers.
Overall, the Spears & Associates, Inc., restimulation market survey results found relatively little interest in restimulation in 1996, and the authors forecast a flat US refrac market of about 470 refracs through the year 2000.
The survey predated the massive refracture market that developed following extremely successful refracturing programs in the DJ Basin of eastern Colorado and in the Barnett Shale in north Texas. DJ Basin refracturing began in 1997, and Barnett shale refracturing begain in 1999. By the end of 2004, more than 1,500 refracs had been pumped in the Codell formation of the DJ Basin, and in the same time frame, more than 350 refracs had been pumped in the Barnett shale. By 2009, several thousand additional refracs have been pumped in the DJ Basin, and some Codell wells have been refraced four times. The current dilemma is when to refrac and not if refracs are necessary.
In 2007, Reservoir Development completed an updated restimulation survey. Several subsequent posts will summarize the results of the 2007 survey.
A couple of years ago, I attended a Society of Petroleum Engineers (SPE) Applied Technology Workshop (ATW) on refracturing in San Antonio, Texas. After the workshop, my impression was that anyone attending the meeting would think the only reason to restimulate a reservoir is fracture reorientation. Fracture reorientation is one reason refracturing is successful, but not the only reason to restimulate a reservoir. The reasons for restimulation following a primary treatment can be categorized as follows.
Remediation. A premature screenout during the primary fracture treatment can result in a very short effective fracture half-length, a damaged fracture face, and a plugged proppant pack. If the cause of a screenout is known or inferred from the treatment records, a refracture treatment is sometimes performed immediately after correcting the problem to obtain the desired fracture half-length and conductivity. Alternatively, a damaging fluid system, for example, a system that does not degrade following a treatment, might allow a fracturing treatment to be pumped as designed, but it can also either plug the proppant pack or significantly reduce fracture conductivity. With a damaging fluid system, the impact can be immediate, that is, a well may not flow back, or the production profile might show the effects of slow fracture clean up over time. Alternatively, formation fines migration or proppant crushing can damage fracture conductivity over time. With proppant-pack damage, a remedial chemical stimulation treatment is sometimes effective, or with severe fracture conductivity damage, a refracture treatment can be required for remediation. As reported by Williams(2004 - subscription required), a recent refracturing program in South Texas Vicksburg is an example of a fracture remediation project that attempts to identify refracture-candidates based on unsuccessful primary fracture treatments or suspected proppant-pack damage.
Reorientation. Refracturing programs in the Barnett shale and Codell are believed to be successful because of secondary fracture azimuth reorientation or by connecting a complex fracture network back to the wellbore. Ebel and Mack(1993) theorized that the directions of maximum and minimum stress can change with pore pressure reduction from production. Consequently, a refracture treatment pumped after significant production can initiate and propagate in a plane other than the primary fracture treatment. Wright et al.(1994) used tiltmeter interpretations to demonstrate that the fractures propagated during a 1993 refracturing program in the Lost Hills Diatomite reoriented to a plane different than the original 1990 tiltmeter-mapped primary hydraulic fractures. In a subsequent study, Wright and Conant(1995) demonstrated using tiltmeter interpretations that the fractures from refracture treatments n the Van Austin Chalk oil field in Texas reoriented by as much as 56° from the original fracture azimuth.
Siebrits et al.(2000) presented the results of a field experiment in the Barnett shale using tiltmeters during the original fracture treatment and subsequent refracture treatment, and the authors concluded that hydraulic fracture reorientation was occurring during Barnett shale refracs. However, since 2000, and after more microseismic mapping data has become available, Barnett refracs may not involve reorientation per se. That is, reorientation implies that a refracture treatment creates a planar fracture offset by some angle from the primary fracture(s). Instead, refracture treatments can also be dilating existing fractures and connnecting a more complex fracture network back to the wellbore (fractures connecting fractures connecting fractures). A recent paper by Wolhart et al.(2007) reported a tiltmeter study of Codell refracs in the DJ Basin of Colorado. The tiltmeter interpretationssuggested that, in general, reorientation was occurring, but also suggested that complex-fracture propagation was observed during Codell refracs.
Bypassed Pay. Wells completed in multiple layers with hydraulic fractures can contain layers bypassed intentionally to pursue higher grade pay and layers bypassed inadvertently because of ineffective fracture treatment diversion. For example, an average of 26 sands are targeted from fracturing in a typical Piceance basin Mesaverde low permeability gas well using three to five fracturing treatments with perforation-friction controlled diversion (limited entry). Esphahanian and Storhaug(1997), in a production log study of 13 Piceance basin wells, found that after fracturing, 28% of the targeted sands produced less than 10 Mcf/D. A similar production log study presented by Eberhard and Mullen(2003) from the Jonah field in Wyoming, where each well can contain 30 to 40 low permeability gas sands targeted for fracturing, found that after completion 35% to 40% of the sands were not signficantly contributing to production. In some cases the noncontributing sands may have been successfully fracture stimulated, but either the reservoir quality is extremely poor or the fracture was damaged by subsequent uphole completion operations. In other cases, the fracturing diversion technique failed, and the targeted sands were inadvertently bypassed.
More sophisticated fracture diagnostics, including radioactive tracers and microseismic mapping, confirm that layers targeted for fracturing are routinely inadvertently bypassed. Wolhart et al.(2005) noted that 7% to 19% of the perforated intervals were bypassed or ineffectively stimulated based on microseismic mapping of 13 limited-entry fracture treatments in 4 Piceance basin wells, and Craig and Odegard(2008) presented evidence from microseismic mapping, production logs, well tests, and refrac diagnostics confirming inadvertently bypassed pay in a Piceance basin well.
Of the three reasons for restimulation–remediation, reorientation, and bypassed pay–all can add incremental reserves from a refrac treatment, but refracturing to stimulate bypassed pay in wells producing from multiple layers may hold the largest potential for adding incremental production if, as some data suggests, 10% to 30% of the layers targeted form fracturing are inadvertently bypassed during the initial completion.
In summary, fracture reorientation is not the only reason for restimulation. It’s the most common reason, and the refracturing success in the Barnett and Codell may make it the most desirable reason to pilot refracturing projects in other areas, but refracturing for remediation and refracturing to stimulate inadvertently bypassed pay are also valid reasons for refracturing.
DrBubba, aka Dr. David P. Craig, in addition to owning Reservoir Development Consulting is also an employee of Halliburton. Consequently, Halliburton requires that DrBubba post the following disclaimer:
The information on this site is mine and does not necessarily represent Halliburton's position, strategy, or opinion.
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