Advances Improve Hydraulic Fracturing

E. Lance Cole

(Tech Connections Article, December 2001, American Oil and Gas Reporter)

TULSA—Although a mature technology, advances continue to be made in hydraulic fracturing.

These improvements are important. In its annual outlook on U.S. independent’s drilling plans reported in January 2001, The American Oil and Gas Reporter notes that independents consider fracturing/stimulation as the technology area that could have the most beneficial impact on their operations, and that has been true for the last couple years.

In direct response, the Petroleum Technology Transfer Council developed a state-of-the-art summary published in the first quarter 2001 issue of its newsletter, PTTC Network News (http://www.pttc.org/news/v7n1.htm). That summary highlights topics such as fracturing diagnostics and mapping, water fractures, and restimulation candidate selection.

Hydraulic fracturing is particularly important for producing natural gas. The Department of Energy’s National Energy Technology Laboratory made an award to Schlumberger-Holditch Reservoir Technologies to discover how important. Schlumberger-HRT will review the number and types of stimulation treatments, treatment costs, and natural gas production and price relationships.

To ensure a comprehensive study, Schlumberger-HRT will engage other high-pressure pumping service companies and key gas well operators. Results of this assessment will provide insights for future research and development, support natural gas policy development, and provide guidance for natural gas resource development strategies. Contact DOE’s John Duda at 304-285-4217 or jduda@netl.doe.gov for more information.

Considering the large number of mature wells in the United States, advances in restimulation work are critical. Although there are 20,000-30,000 hydraulic fractures performed each year, there are only a few hundred refracs performed, despite the thousands of wells that are potential candidates.

Many operators still perceive refracturing to be a high risk venture, and it can be if one looks at production alone and embarks without in-depth studies. But when the homework is done properly, 90% success rates are reported, and incremental reserves cost $0.25 an Mcf or less. The potential is there, but it must be done right.

Successful Practices

Since 1998, the Gas Technology Institute and its contractor Advanced Resources International, has conducted field R&D work directed toward determining the best approach(es) for selecting restimulation candidates. Three basic approaches—production statistics, virtual intelligence, and type curves—have been evaluated in the East Texas, Piceance, and Green River basins.

Although lowest in data and interpretation requirements, analyzing production statistics (or comparing well performance with offsets) suffers in identifying good wells that could perform even better, and it lacks in areas where reservoir heterogeneity is high. Type curve analysis does require more data, including petrophysical evaluation, but it can be managed. Interpretation requirements are high, however.

The highest data requirements are for virtual intelligence (neural networks, genetic algorithms, fuzzy logic) methods, which can be an issue. But the data interpretation requirements for virtual intelligence are low compared to type curves.

The different candidate selection methodologies select different wells for different reasons.  Fundamental findings regarding their use are:

• Where reservoir quality is relatively uniform and production has been relatively stable, production statistics should be considered.

• When production data quality is good and petrophysical information is available, type-curves should be considered.

• When reservoir and completion/stimulation complexity is high, virtual intelligence methods should be considered.

The above insights were excerpted from a Society of Petroleum Engineers distinguished lecture presentation by GTI’s Steve Wolhart (281-876-2323 or steve.wolhart@gastechnology.org), and an article in GTI’s magazine, Gas Tips. These insights essentially represent a “successful practices” effort on a national scale.

Once appropriate stimulation candidates are identified, the next step for applying successful practices is to analyze and control the fracturing treatment in real-time, a practice often referred to as applying advanced stimulation technology. In that realm, the GTI-developed CD-ROM article, “Guide to Advanced Stimulation Technology” (http://www.pttc.org/tech_sum/ts_168.htm, in the December 1999 PTTC Network News is still valid. The CD includes up-to-date advanced stimulation technology methodology as it applies to candidate selection, real-time analysis, quality control, data set enhancement, stress profiling and post-fracture analysis.

Fracture mapping is increasingly important to optimizing stimulation programs. There are two basic approaches for fracture mapping: using either seismic sensors or tiltmeters (see PTTC Network News, spring 2001, http://www.pttc.org/news/v7n1nn5.htm). Pinnacle Technologies Inc. (http://www.pinntech.com), expanding on earlier R&D work, is a key player in fracture diagnostics. Its fracture diagnostics capabilities include surface tiltmeter fracture mapping, downhole tiltmeter fracture mapping, microseismic fracture mapping and hydraulic impedance testing.

PTTC’s summary also references a new approach for cleaning up the gel damage sometimes experienced in hydraulic fracturing treatments. Micro-Bac International (http://www.micro-bac.com/) developed its Gum-Bac^TM product specifically for repairing gel damage. Attractive results in two wells are documented in a PTTC-developed case study (http://www.pttc.org/case_studies/PTdigest5-01.htm). Micro-Bac indicates that interest remains strong and some more domestic treatments are in the wings, but as of yet, there is not a large database of domestic applications.

Regional Best Practices

National-level successful practices are great, but wells/reservoirs vary regionally, so there is a great need for regional best practices. In a very simplied form, regional best practices have been transferred through some PTTC workshops. For example, in a February 2000 workshop in Kansas, industry shared bottom line insights for treating regional reservoirs (http://www.pttc.org/solutions/208.htm).

In the deeper Morrow gas reservoirs in western Kansas, tip screen-out designs show an economic advantage over conventional fracture designs. For the Chase and Council Grove formations in the Hugoton area, conventional fracture designs (high sand concentrations, large sand, and clean fracturing fluids) are favored. The shallower depth and lower stress on the proppant allow conventional designs to provide adequate conductivity. Production performance with conventional designs is nearly as good as with tip screen-outs, and costs are less than half.

From GTI’s experience, fundamental findings regarding the process of finding successful practices, whether nationally or regionally, are:

• Improvement comes in many small packages; do lots of little things right, repeatedly.

• Technology and effective practices are routes to success; it is the combination of technology and practice that succeeds

• It is important to maintain detailed records; go beyond morning reports.

• A collaborative approach has significant economies of scale; it enjoys the power of leverage.

• No one can identify successful practices alone; multicompany studies with third party access to full data draws out the secrets for everyone’s benefit.

Enhancing Fracture Technology

 Applied R&D studies are essential to the evolution of technology. As an example of how these evolutions are occurring. DOE’s National Energy Technology Laboratory (NETL), through its Strategic Center for Natural Gas, awarded a project in August to the University of Texas at Austin to create an improved hydraulic fracturing model using laboratory tests, improved fracture simulations, and analysis for the Bossier play (field), southeast of Dallas.

To confirm the predictions of such a model, a fracture monitoring program is proposed with a detailed analysis of current and future fracture treatments. Anadarko Petroleum Corp. in Houston is partnering in this project. For further information, visit NETL’s website, http://www.netl.doe.gov, or contact DOE’s Jim Ammer at 304-285-4383 or jammer@netl.doe.gov.

A second example relates mixing proppant and fluids downhole to reduce risk and lower costs. RealTimeZone Inc. (RTZ) of Roswell, NM, working in a project partially funded by DOE’s NETL, has been developing and demonstrating a technique for mixing fracture fluids down hole, rather than on the surface. Potential advantages of the approach include lower surface pumping pressures—which improves safety and reduces horsepower requirements—and increased ability to alter the treatment mixture at the perforations on a real-time basis.

RTZ’s first field application occurred in November 2000 in a 12,300-foot Morrow gas well in the Sand Point Field of Eddy County, NM. According to George Scott with RTZ, "The treatment consisted of a methanol gel with 7,000 pounds of bauxite proppant pumped down the annulus, and 40 tons of liquid carbon dioxide pumped down the tubing. Tubing pressure never got above 6,000 psi, and the casing side was never above 5,000 psi. Pressures averaged 5,000 psi, but if we had pumped the job in the conventional manner, the pressures would have averaged closer to 10,000 psi."

Liquid CO₂ was used because, after the proppant has been placed, the drop in treating pressure turns the CO₂ from liquid to gas, allowing the fracturing fluid to be produced back from the formation at a faster rate. A post-fracture tracer log showed that the treatment had been placed as designed.

Initial production from the well was 200 Mcf-250 Mcf a day, and one year later, production was holding steady at 250 Mcfd—all from a well previously scheduled for abandonment.

In continued work within the DOE-funded project, RTZ is on the verge of its second field application, this time in a stripper oil well using gelled lease oil and CO₂. To make it available to industry on a broad scale, RTZ and NETL have licensed the technology to Halliburton. Future improvements will flow to Halliburton for industry’s ultimate benefit.

NETL began working with RTZ on the hydraulic fracturing project in May 1999. For more information contact George Scott at RTZ at 505-622-6713 or glsrtz@aol.com, or Gary Covatch at NETL at 304-285-4589 or gcovat@netl.doe.gov.

Solid Propellants

Hydraulic fracturing will remain the dominant stimulation technology, but there are niches where other technologies have application and are evolving. One example is a solid propellant technology developed by J Integral Engineering. J Integral Engineering’s GasGun generates high-pressure gases at a much slower rate than explosives, yet much faster than hydraulic fracturing. This leads to multiple fractures (confirmed by bore hole video logs) that grow radially from 10 to 100 feet, but height growth is minimal.

Although much shorter than hydraulic fracs, the technology’s cost fits marginal well economics, where conventional hydraulic fracture treatments are often unaffordable. In a published case study, an operator noted successful application in marginal Trenton limestone wells in Illinois, with treatment payout typically occurring within two weeks or less. 

Success has also been observed in the Mid-continent treating tight sections in the Arbuckle formation, allowing for low-pressure acid treatments (see PTTC’s North Midcontinent newsletter: http://www.kgs.ukans.edu/PTTC/News/2001/q01-2-2.html). More than 30 treatments have been performed in Kansas.

One operator has treated six wells with the GasGun, and five of six were considered successful. The sixth well broke into the water zone. Combined production in three of the wells rose over two months to 30 barrels of oil a day from 8.7 bbl/d prior to treatment. Because of the relatively inexpensive cost of the treatments, payout occurred within days or weeks. The operator is continuing to monitor the wells, and will soon be performing similar treatments on additional wells.

The potential of solid propellant stimulation technology in marginal well applications is evident, but it is important to note that documentation and development of “successful practices” is essential for this and other new technologies.

E. Lance Cole is National Project Manager with the Petroleum Technology Transfer Council in Tulsa, where he coordinates communication and activities among PTTC’s 10 regions and serves as a technical resource for the headquarters group. Cole has prior experience with major, large independent, and engineering consulting companies, focused on reservoir engineering and technology transfer. He has a BS in chemical engineering from South Dakota School of Mines & Technology, and an MS in management from Southern Nazarene University. He is a licensed professional engineer in Oklahoma.