Table of Contents

Vol. 7, No. 1
1st Quarter 2001

Improvements in Fracture Stimulation Technology
by Karl Lang, Hart/IRI Fuels Information Services

During 1999 the oil and gas industry spent $850 million on about 20,000 North American fracture stimulation treatments. Hydraulic fracturing is an economic necessity for low permeability sandstone natural gas completions and it is clear that the most important contribution of improved fracturing technology will be in helping to meet the growing demand for domestically produced natural gas.

The most important questions asked by any engineer responsible for fracturing are: Can I be certain the dimensions and direction of the created fracture are optimal? Can I achieve the same (or more) productivity improvement at a lower cost? This article looks briefly at how engineers are looking to new technologies to answer these fundamental questions.

Hydraulic Fracturing Diagnostics

Optimizing the hydraulic fracturing process is difficult because engineers must rely on indirect measurements such as treating pressure or post-fracture production data to infer the results of the treatment. Gas Technology Institute (GTI - formerly GRI), together with others, has developed commercial fracture mapping technologies that attempt to overcome these limitations by directly imaging the dimensions and direction of a fracture as it is created.

Microseismic Hydraulic Fracture Mapping

GTI's FRACSEISSM microseismic fracture mapping service (now offered by Pinnacle Technologies Inc.) uses seismic sensors placed in an offset well to detect microseisms generated during treatment. A formation is stressed during a hydraulic fracture treatment because of leakoff-induced pore pressure increases and net treating pressures. This leads to small shear slippage's similar to earthquakes along faults. These micro-slippages (microseisms) emit elastic waves that can be detected by geophones in offset wells. The microseisms are located and the data is used to create maps of the hydraulic fracture geometry. To date, about 60 fracture treatments have been mapped in the United States, Canada and Mexico.

Downhole Tiltmeter Hydraulic Fracture Mapping

Another new technology for hydraulic fracture mapping employs downhole tiltmeters. As with microseismic monitoring, multiple instruments (tiltmeters in this case) are run on wireline in an offset well. Creating a hydraulic fracture involves parting the rock and deforming the reservoir. Downhole tiltmeter mapping simply measures the fracture-induced deformation in an offset well (or wells) versus time and depth. The data is inverted to obtain created fracture height, length and width.

To date, downhole tiltmeters have been used to map over 400 fracture treatments in multiple basins. This technology is now being used by Pinnacle Technologies, Inc. to field a new variation of the downhole tiltmeter system that can be deployed on wireline within the treatment well itself.

Treatment well tiltmeter mapping involves running an array of instruments (3 to 10 tools) in the treatment wellbore prior to the fracture treatment. The tools are coupled to the wellbore with centralizers. A fluid-only treatment (no proppant) is pumped (waterfrac, acid frac or minifrac) and the induced tilt at each location is measured in real time and telemetered to the surface.

"Deploying a tiltmeter array in the well being treated, rather than in an offset well, makes this technology much more accessible to the smaller operator trying to do a better job of fracturing," says Kevin Fisher, Business Development Manager with Pinnacle. "Our tool can be used during a pre-treatment minifrac to obtain an actual fracture height and width measurement that can then be used to fine-tune the fracture model for the main fracturing treatment. Through January 2001, Pinnacle has run the new array during five minifracs and fracs in California diatomite wells, and also during an acid frac in Oklahoma's Hunton, with good results.

Using these techniques to fine-tune hydraulic fracture models in real-time will allow engineers to optimize the frac job while it is being pumped. "Our goal is to use the fracture mapping data to calibrate the model, so the model can be used to accurately predict fracture behavior, rather than to simply explain treatment results," says Fisher.

Mixing Proppant and Fluids Downhole Reduces Risk and Lowers Cost

Pumping fracture treatments at high pressures is expensive and can be a safety hazard. For these reasons, older wells are often rejected as candidates for high pressure treatments. A DOE-sponsored project in New Mexico has shown that mixing fracture fluids at the bottom of the well, rather than on the surface, may lead to a safer, lower cost technique for fracturing wells. Another benefit of this approach is an increased ability to alter the treatment mixture at the perfs, during the treatment.

RealTimeZone Inc. (RTZ), of Roswell, NM, used their downhole mixing technique for the first time last November in a 12,300-foot Morrow gas well in the Sand Point field of Eddy County, NM. According to George Scott, a manager at RTZ, "The treatment consisted of a methanol gel with 7,000 pounds of bauxite proppant pumped down the annulus and 40 tons of liquid CO2 pumped down the tubing. Tubing pressure never got above 6000 psi, and the casing side was never above 5000 psi. Pressures averaged around 5000 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. The Sand Point well had been scheduled for abandonment but now is producing between 200 and 250 Mcfd. A post-fracture tracer log showed that the treatment had been placed in the zone as designed.

"The value of this approach is two-fold," explained Scott. "Lower friction pressures mean less hydraulic horsepower and thus less cost, and the surface control of the downhole mixing permits a degree of real time influence over the treatment that isn't possible when you're mixing the treatment fluids at the surface. This can mean the difference between success and failure, particularly in wells that have a tendency to screen out prematurely." Changes in stimulation pressures monitored at the surface also allow an operator to know if the fracture is being created as planned. If necessary, the operator can change the fluid mixture to ensure that a fracture goes in its intended direction.

RealTimeZone can also combine this downhole mixing methodology with a downhole, real-time, surface readout fracture monitoring system to give an even more accurate picture of where the fracturing fluids are going. Working with Halliburton Energy Services to incorporate their gamma-ray Spectrascan log, RTZ has performed a treatment in another Eddy Co., NM well completed in the Willow Lake Delaware oil reservoir, and has more scheduled for the near future. Spectrascan utilizes distinctive radioactive tags (typically encapsulated tracers provided by CoreLab's ProTechnics) on both proppant and fluid to reveal the relative distribution of pumped material.

The Energy Department's National Energy Technology Laboratory (NETL) began working with RealTimeZone on the hydraulic fracturing project in May 1999. With a total project cost of $1.3 million, and with the federal government contributing $922,000, the project is now in its last two phases involving field testing the downhole mixing and real-time monitoring methodologies.

Waterfrac Success Depends on Reservoir Selection

Ten or more years ago, U.S. natural gas producers began to look seriously at unconventional gas resources (tight sands, gas shales, coalbed methane) as a means to replace gas reserves, but in many cases, the high cost of fracturing treatments made the reserves uneconomic. In the mid 1990s, several cost-conscious operators tried lowering costs by reducing the proppant concentrations in large treatments and using less expensive, lower viscosity fluids. In several basins the results were significantly lower costs and as good or better well productivity. The term "waterfrac" (also called light sand fracs) was applied to these treatments. While waterfracs are not applicable in all situations, proper candidate reservoir selection can help determine where they are appropriate.

A typical waterfrac includes:

• large volume of water (1,000 to 2,500 bbl/foot of gross pay) treated with friction reducers, surfactants and clay stabilizers
• 50% pad with constant 0.5 ppg sand concentration
• tail-in with 0.5 to 2 ppg for last 1% to 5% of treatment, to ensure good communication between the fracture and wellbore area.

According to Mike Mayerhofer, Staff Engineer with Pinnacle Technologies in Houston, "Waterfracs appear to work through a combination of mechanisms. The walls of the fracture are rough and when the surfaces are slightly offset by shear forces there is a "self-propping" phenomenon that may be taking place. Rock debris in brittle formations can enhance this behavior."

The performance of waterfraced wells has been reported on by a number of operators (Table 1). Experience has shown that there are some general guidelines that can be followed when considering waterfracs. According to Mayerhofer, "Operators should look to apply waterfracs in the most marginal, lowest permeability areas first and then proceed to better areas. Naturally fractured, "stiff" rocks in normal stress environments are good candidates." When designing a waterfrac, Mayerhofer suggests that, "Optimization with respect to fluid volume, injection rate, pad size, proppant concentration, etc. will be field specific. Not all recent applications of waterfracs have been successful. However, their success in particular situations indicates that operators who can find the right "niche" for this approach can profit.”

Damage Removal Using Microbiological Tools

An important part of any fracture treatment is reduction of the gelled fluid's viscosity after the frac treatment has been performed so that produced fluids can flow through the proppant matrix. Chemical or enzymatic agents that degrade the polymer structure or cross links in the gel (termed "breakers") are used to accomplish this.

In a significant number of fracturing operations, the breaking process is incomplete, resulting in less than optimal flow. A new strategy for repairing such damage is the use of biological culture products specifically targeted to degrade the gel polymeric structure. One such product, produced by Micro-Bac International of Round Rock, TX, and called Gum-Bac™, is specifically designed to degrade the carbohydrate backbone of guar gels. This reduces viscosity and promotes removal of the gel from the fracture matrix.

"The results of Gum-Bac applications have been very encouraging," says Brian Cummings with Micro-Bac International. Cummings cites a well in southwest Texas that had been treated with an acid fracture stimulation fluid incorporating a complex copolymer, where after treatment production could not be restored. Micro-Bac treated the well with Gum-Bac to degrade the copolymer and a large amount of polymer material was immediately freed up. "The well produced over 14 MMcf during the first month, declined steadily over seven months to about 3 MMcf per month, then dropped further as it began to produce “slick” water (indicative of polymer). Long-term outlook is uncertain, but with payout occurring in less than a month, economics are highly favorable.

Restimulation Candidate Selection Methodology To Be Tested

According to work carried out by the Gas Technology Institute, many operators make restimulation decisions without benefit of downhole data and base their decisions only on production information, which may not be a good indicator. The industry tends to restimulate only the worst performing wells and not those that have the most potential for improvement. Gas Technology Institute (GTI) has found that refracs are only 2-3% of total US fracture stimulations, and most of these involve gas wells in the US Midcontinent, Rocky Mountains, and South Texas regions. There may be significant potential, however, if operators can apply a successful methodology for identifying candidate wells.

GTI is finishing up a two and a half year study on the best way to select restimulation candidates. The study focused on developing an efficient candidate-selection methodology and included demonstration tests in three tight gas fields. After analyzing 200-300 wells in each area, GTI refraced two wells in the Mesaverde formation in the Piceance basin of Colorado, four wells in the Frontier formation of the Green River basin of Wyoming, and three wells in the Cotton Valley formation in the East Texas basin. According to Scott Reeves, Vice President of Advanced Resources International, a GTI contractor managing the analysis, "Seven of the nine restimulations were considered successful, and the program did determine that refracs could succeed if operators pay attention to procedures."

GTI developed and tested three distinct processes for selecting restimulation candidates. Process I looked at production data and selected wells that were underperforming relative to their offsets. Process II selected wells where "less-than-best" practices were employed using detailed well data, pattern-recognition and neural networks. Process III employed type-curve matching to select wells with the greatest potential. Each method yielded different candidate wells and GTI did a benchmark study on a set of synthetic wells to gain insight into each method's effectiveness for ranking candidates. GTI found Process III to be the most reliable for identifying high-potential restimulation candidates.

GTI has begun a final test of this methodology with Patina Oil & Gas Corp. in the Codell gas-condensate reservoir in the Wattenburg field area in Colorado's Denver basin. In 1999 Patina restimulated 110 wells and added 30,500 boe/well to gross reserves. Patina has had considerable success in selecting restimulation candidates using an algorithm that considers a weighted average of such factors as formation porosity-feet, gas-oil ratio, peak production, cumulative production, expected ultimate recovery, and differences in the ultimate recovery from offset wells. Patina estimates that while more than 1000 wells have been refraced in the area, they represent less than a fifth of potential restimulation candidates.

"The Patina wells represent an excellent opportunity to test the methodology developed by GTI," said Reeves. "We will apply the methodology using only pre-restimulation data from Patina's wells and develop a list of ranked restimulation candidates. Then we will compare our selections with the actual results of Patina's program and, based on post-restimulation performance, see if we were successful in picking the best candidates."

The Strategic Center for Natural Gas at DOE's National Energy Technology Laboratory (NETL) is funding similar analyses that aim to provide methodologies for producers wishing to select stripper gas wells for remediation. Three projects initiated in the Appalachian and Midcontinent basins are based on decline curve analysis, offset well performance comparisons, and type curve analysis. According to Gary Covatch, Project Manager at NETL, "We hope to offer producers a portfolio of candidate selection methods so that they can pick an approach that works for their particular area. The focus is on developing low-cost methods for determining the wells with the highest potential for productivity improvement."

New Technologies Focused on Squeezing More from Existing Wells

The improvements outlined above focus on finding ways to reduce the cost of fracturing gas wells or on improving the performance of wells previously fractured. This path will have to be followed if independent producers are to meet the strong and growing demand for domestically-produced natural gas in an environment of dwindling exploration acreage opportunities.

(Note: Please see expanded version of this article online at www.pttc.org for a complete list of references)