Friction reducers are expected to play critical roles in fracturing, some better than others.
Shale producers are belatedly realizing that there are many variables that can alter the performance of these chemicals used to reduce the power needed to hydraulically fracture a reservoir, and in higher doses, to thicken fluid, making it possible to deliver proppant more efficiently.
There are wells that can justify paying more for a friction reducer formulated to stand up to difficult chemical challenges, and others that cannot.
But there is no guide that describes how these key additives perform. Those who do evaluations will realize that a lot of details about friction reducers are proprietary and no industry standard provides guidance about the information needed to thoroughly assess their compatibility with reservoir conditions.
“There hasn’t been a really good method to quantitatively evaluate friction reducers and what they do,” said Paul Carman, the completion fluid advisor for ConocoPhillips, who has not figured out what that method might be.
Recently, Occidental Petroleum took a stab at answering the question with a paper discussing its evaluation of friction-reducer performance.
It’s not a short answer. The paper delivered at the Unconventional Resources Technology Conference (URTeC) does not offer names of the products tested, how many were tested at any stage of the process, or details that might identify top performers (URTeC 5249).
Those who dig deeper and ask fracturing experts will learn that the best friction reducer will depend on the job. And money, time, and research are required to gather the data needed for informed decision making.
When Occidental began working on a system to evaluate friction reducers, they found little had been written on how to do it, said Nancy Zakhour, Occidental’s well design lead, a coauthor of the paper.
There was a general paper from Shell on well chemical evaluation but little else. That shows how oil companies have come to rely on others to do performance testing.
The shale business has not shown much interest in chemical performance until recently. Greater attention has turned to the many details that can incrementally improve shale well performance and to the research showing how friction reducers perform badly due to chemical reactions in some wells.
These are not the only additives that may be affected by chemical reactions during and after fracturing. But friction reducers have grabbed the most attention because they do a couple important jobs.
- They are used to reduce resistance during pumping along a long lateral, which can affect the cost of the job because lowering the friction decreases the hydraulic horsepower needed.
- When used in higher volumes, they become high-viscosity friction reducers (HVFR), which have the added benefit of being able to carry higher concentrations of proppant
“HVFRs bring out the best of both regular friction reducers and gelled fluids in a single and clean system,” Zakhour said.
Occidental chose chemicals for laboratory testing by doing its own legwork and building a database. It then hired an independent lab to run tests it developed with advice from a chemist on staff. The ultimate test was based on fracturing performance, which was measured in various ways related to the time and cost required to effectively fracture a stage and the productivity of that section.
Do It Yourself
Occidental created its own method because big oil companies got out of the chemical-evaluation business decades ago when they began relying on suppliers for testing and advice.
That relationship has been changing in recent years. First, some companies in the shale business stopped relying on pressure-pumping companies to supply the chemicals and began buying direct.
Companies that first took control of chemical purchasing to reduce costs are now faced with the question: Based on the performance, what is the best value? When Occidental started building its evaluation database, it decided to not rely on supplier information alone.
The goal of the process was to eliminate any bias by paying an independent lab to run the tests it had chosen, Zakhour said.
Building a chemical-performance database using supplier information highlights the fact that the information offered varies. Some details are not disclosed because they are considered proprietary.
Ingredients are often not listed, and the performance information offered varies in quantity and quality. The data needed for apples-to-apples performance comparisons were simply not available, Zakhour said.
Those on the supply side also see selective data disclosure. “It is difficult to compare data” from different suppliers, said Brian Price, vice president of technology at Rockwater Energy Solutions.
On the other hand, there is no industry standard guiding suppliers in testing. And the ultimate test is how the friction reducer performs during fracturing, which requires knowing a lot of details about the fracture design and the well. That is not the sort of detailed information operators are likely to make public.
Creating a standard requires an agreement on what to measure. Price said most tests now are focused on how the friction reducers influence fracturing performance, rather than considering the possible long-term effect on production, which is hard to quantify.
“Fluid compatibility and formation compatibility are overlooked as the key focal points are horsepower, volume, and time to complete the frac,” he said.
Starting the Search
Occidental began its search for a “game-changing” HVFR by building a database it used to narrow down the number that went through lab testing.
While they tried to avoid bias by relying on supplier data, they did not shut them out of the evaluation process. Zakhour said Occidental “leveraged the vendor’s expertise’’ on performance issues such as the effect of total dissolved solids (TDS).
The tests, chosen with the advice of an Occidental chemist, measured such things as the time it took for sand to settle in fluid thickened with different HVFRs. They also tested varying concentrations to measure the optimal amounts to use.
Other tests measured the amount of breaker needed to shear the polymers in each product into smaller molecules, which reduces the risk of them causing issues. They also observed the breaker performance at different concentrations.
The goal of the system was to identify the best performance in varying well conditions. For example, a friction reducer used with high-TDS produced water must be formulated to stand up to that specific mix.
In completions where the water pumped is less challenging, a lower-cost additive may be the best choice, unless trumped by other reservoir-related variables.
The Chemistry Test
Chemical selections depend on the water used in fracturing because much of it comes from shale wells.
Companies treat the water to filter out solids and kill bacteria. But they leave the dissolved solids—comprised mostly of what is commonly known as salt—sodium chloride—and other salts containing reactive elements such as calcium, iron, or barium. The methods available to remove them are costly and disposing of these solids is an issue.
It has long been known that fluids with high TDS hurt the performance of some friction reducers. There is a growing body of research investigating what happens to polymers in friction reducers when a negatively charged additive (an anion) reacts with a positively charged ion (a cation) such as iron, calcium, or magnesium.
“When an anionic friction reducer meets a cation such as iron, the polymers in the additive tangle and coil on themselves,” said Lauren Burrows, a research associate at the National Energy Technology Laboratory (NETL) in Pittsburgh, Pennsylvania.
“Friction reducers work best when the polymers are stretched out in the direction of flow, so tangled and coiled friction reducers do not do their jobs very well. When this tangling process occurs to an extreme level, semisolid amalgams of friction-reducer polymers—often called “gummy bears”—can develop,” Burrows said.
The best-known examples of gummy bears were found in Oklahoma where URTeC paper (URTeC 2487) revealed they are likely due to interactions between a friction reducer and iron in the well. Since the paper was published in 2020, gummy bears have been observed in a few other places (JPT report 2020).
For example, the technical sales manager at Reliance Well Services asked NETL why customers had found black gunk coming out of three wells out of more than a 100 in the two fields where they occurred.
The lab received samples of the gunk but ruled out testing them because they could damage expensive lab equipment in the same way they clog choke valves.
Instead, they asked for samples of the two friction reducers used in the problem wells, then put a small amount of them in a beaker with iron and deionized water to strictly limit the chemical variables. The result: Nothing changed, said Burrows, who worked with Derek Hina, technical sales manager for Reliance.
When they substituted tap water, however, the friction reducer gelled. That water, like the fresh water used in the wells, was produced in an area where hard water is common. Burrows said they would be trying to pin down what contributed to that reaction.
Oddly, the friction reducers used were ones that would normally not react to iron because they and the metal are both positively changed, making them cationic.
Chevron recently reported on a similar test, where it exposed friction reducers to a brine including reactive ions such as calcium, strontium, barium, and iron, in a slightly acidic fluid (URTeC 5170).
Out of the four additives tested, three reacted to the iron, creating either particles or a gooey substance.
The stable survivor in round one was nonionic—it did not have a charge, making it less likely to interact with a positively charged ion such as iron.
The paper said the charge of the other friction reducers tested was listed as “was not known” because it was labeled as proprietary in the database. This gap in the data makes it hard to know what to make of the results.
Depending on the charge of the three additives for which the anionic or cationic status was unknown, it could suggest most friction reducers are likely to break down if exposed to those conditions, or it could just be three products that are poorly suited for the chemistry.
As the paper explained, if those friction reducers are negatively charged (anionic), they would be likely to react to a positively charged ion like iron, making them a poor choice in a well where the water chemistry makes those reactions likely.
In those situations, a more expensive, positively charged (cationic) friction reducer is often used because chemical reactions between molecules with the same charge are less likely.
The questions raised show the uncertainty faced by those who buy friction reducer with little knowledge of its makeup.
The Final Word
When it came time for Occidental’s final evaluations, performance was based on a cost analysis of the friction-reducers’ performance while fracturing, including the production performance. The results were compared to the performance of a baseline design using either a conventional friction reducer or a linear gel system.
Lab testing narrowed the field to a few products chosen for in-well testing.
Each of those that made the cut was pumped in a well test, beginning with a few stages in a well where it was compared to the performance of other options and to a baseline friction reducer. All other completion design variables remained the same to ensure they did not affect the results. Those products that advanced were ultimately used in full well tests that were then compared to wells using a baseline design.
The winners were chosen based on criteria that determine the time and cost of an effective job: friction reduction and horsepower consumption, water volume used, and the time required to stimulate each stage.
The ability of an HVFR to carry higher concentrations of proppant was a critical measure because it delivered the greatest efficiency improvements and savings, Zakhour said.
Production results varied for the best picks. In one case study with HVFR, it significantly reduced the cost of the completion of a well that produced about 37% more fluids.
In a second instance, a well pumped with the selected HVFR option produced 15% less total fluid than a slickwater well, but the paper noted that the value of the time and water saved exceeded the value of production difference.
The testing program was also used to determine how much of each product should be used for fracturing. The paper pointed out that contractors sometimes pump more than the recommended amount of friction reducer to ensure the job goes smoothly, which increases the cost of the job.
Monitoring completion practices are among the long-term efforts needed to ensure that what was learned from the testing program is applied and to continue looking for ways to incrementally improve results.
The value of what was learned will depend on how it is used in the future, which will require organizational support from departments ranging from completion engineers and asset managers to purchasing and logistics.
The project team recruited a steering committee and sponsors within Occidental to help deal with “bottlenecks, resistance, and managing expectations,” according to the paper.
“If you do not go through this effort, any one of them can hinder the success of the project,” Zakhour said.
Asset teams will select friction reducers based on which of the best choices meets the conditions of a well pad. Over time, further testing may be done as the well parameters change or new products come along.
“The decision is geographic-specific and formation-specific,” Zakhour said. Even contract terms can affect the financial value of different levels of HVFR performance to different operators.
While ConocoPhillips does not have a formal friction-reducer evaluation system, it does run some performance tests in the field, Carman said.
Completion engineers with promising samples from suppliers sometimes do stage-level comparisons. “To know how well it will perform, they have to take it out there and use their engineering skills to do a stepdown test,” Carman said.
The test uses a series of pressure reductions to determine the conductivity of fractures near the wellbore after fracturing.
He warned that the best pick today may not be so a few months from now because fracturing-water quality often changes. “In a lot of cases, we are not getting consistent water all the time,” Carman said.
For Further Reading
URTeC 5249 High-Viscosity Friction Reducer Testing, Trialing, and Application Workflow: A Permian Basin Case Study by N. Zakhour, S. Esmaili, J. Ortiz, and J. Deng, Occidental.
URTeC 5170 Impact of Fracture Conductivity on Production: How Much Proppant do We Really Need in Unconventional Reservoirs? by S. Naik and A. Singh, Chevron Corp.
SPE 106162 Successful Breaker Optimization for Polyacrylamide Friction Reducers Used in Slickwater Fracturing by P.S. Carman and K.E. Cawiezel, BJ Services Co.
SPE 166471 Comparison of the Impact of Fracturing Fluid Compositional pH on Fracture Wall Properties in Different Shale Formation Samples by R.F. LaFollette and P.S. Carman, Baker Hughes.
Solving the Gummy Bears Mystery May Unlock Greater Shale Production by Stephen Rassenfoss, J Pet Technol.
Can Fracturing Chemicals Hurt Production? There Are Some Good Reasons To Think So by Stephen Rassenfoss, J Pet Technol.
