Novel frac-fluid chemistry meets strict environmental standards for offshore disposal while achieving performance and cost goals.

Developing a fracturing fluid
that can meet today's stringent environmental standards and perform well at a competitive price
as first seemed like a hopeless quest. The key to success was found by getting outside the constraints of traditional oilfield chemical sources. Baker Oil Tools' B9 Emerald Fraq is a hydraulic fracturing fluid system that replaces cross-linked fluids currently in use without changing topsides operations or equipment requirements.
The new fluid includes chemical technology that meets all environmental goals, improves overall fluid performance and maintains pricing levels within 5% of older fluids. Offshore disposability is a significant advantage that reduces operational costs. The new fluid system has a hexane extractable materials (HEM) value for oil and grease that averages less than 10 mg/l, along with a Mysid shrimp toxicology of over 30,000 ppm, which meets the toxicity standard for water-based drilling mud. Additionally, biodegradability meets or exceeds the Organization of European Cooperative Development (OECD) requirement of lessthan or equal to 60% in 28 days.
Meeting requirements
Frac packing has emerged as a preferred method of completing offshore wells in unconsolidated formations such as those prevalent in the Gulf of Mexico. The frac pack operation manufactures and pumps large volumes of stimulation fluids from the fracturing stimulation vessel into the well. Most operations require at least two workstring volumes of fracturing fluid to be reversed out and safely disposed. Greater than 3 miles (4.8 km) from shore, discharging the fluids offshore minimizes costs, risks, logistics and deck space requirements. To qualify as offshore-disposable, the fluids must meet stringent criteria.
Currently, US regulations specify oil and grease levels for well treatment fluids, defined as, "Any fluid used to restore or improve productivity by chemically or physically altering hydrocarbon-bearing strata after a well has been drilled." (40 CFR Ch1, 435.11 (mm)). The 40 CFR provides several key definitions.
No discharge of free oil "means that waste streams cannot be discharged when they would cause a film or sheen upon or discoloration of the surface of the receiving water." The test for free oil is conducted by placing a fluid sample in water and visually inspecting it to see if it sheens.
Oil and grease "means total recoverable oil and grease." The test for total oil and grease takes place in a laboratory using a hexane extraction procedure to determine the HEM defined in EPA 1664 Revision 'A.'
The regulations provide guidelines for four standards:
• Best practicable control technology (BPT) currently available;
• Best available technology (BAT) economically achievable;
• Best conventional pollutant control technology (BCT); and
• New source performance standards (NSPS).
For well treatment fluids the standards are:
• BPT: No discharge of free oil;
• BAT: Oil and grease: The maximum for any one day shall not exceed 42 mg/l; the average of daily values for 30 consecutive days shall not exceed 29 mg/l;
• BCT: Free oil: No discharge as determined by the static sheen test; and
• NSPS: Oil and grease: The maximum for any one day shall not exceed 42 mg/l; the average of daily values for 30 consecutive days shall not exceed 29 mg/l.
Fluid properties
Frac fluids are a complex mixture of polymer and additives that must be balanced to achieve such properties as high viscosity, proper formation compatibility, appropriate breaker and concentration to achieve the desired break times for cleanup. Some jobs may require up to a dozen additives. In developing the new fluid, existing additives that could not meet the minimum environmental specifications were replaced.
The new additives also had to meet the same performance standards as those they replaced. Figures 1 and 2 show viscosity versus time plots for typical fluid compositions used at 175°F (80°C) and 250°F (121°C), respectively. These graphs also indicate effectiveness of the gel breakers to adequately control viscosity during pumping operations. The fluid may be used at or above 300°F (148°C) by increasing the polymer loading, adding a gel stabilizer and using high-temperature breakers.
In addition to meeting normal pumping requirements, these fluids must also meet new specifications regarding HEM, toxicity and biodegradability. Suites of tests were conducted on the entire range of additive compositions for the fluid system to assess the acceptability for these three properties. Since there are not (as of this writing) any directly applicable regulations or standards for fracturing fluids, nearest "equivalent" numbers were used. To determine HEM, EPA Method 1664 Revision 'A' was applied to unbroken gelled fluids. Although not specifically designed for viscous fluids, this method yielded HEM levels below 29 mg/l as shown in Figure 3.
To ascertain toxicity, the fluid was tested using 40 CRF part 136, method 1007.0. Although this method applies to drilling fluids, it gave a reasonable indication of risk levels if discharged. The lowest values recorded as a result of testing a 50-pound-per-thousand-gallon (pptg) guar fluid were about 200,000 mg/l, which indicates an acceptable risk level for this fluid if it were necessary to discharge it.
Biodegradability was determined using the OECD Guideline for Testing of Chemicals. The closed bottle method was used to determine biodegradability in seawater. More than 80% degradation was observed for 35 pptg guar cross-linked with borate salts. Where 60% degradation is a minimum for chemicals, the B9 Emerald Fraq system shows acceptable biodegradability.
New additives
To achieve the fluid properties cited above, five of the six common base fluid additives had to be replaced. The sixth additive, KCl salt, which is used as the primary clay control agent, had to be limited to no more than 2.0% (by weight of fluid) in order for the potassium content to be non-toxic. Of the original additives, the mineral oil-based slurry guar polymer product was the largest contributor to the hexane extractables. Switching to an aqueous-based suspension fluid eliminated the HEM problem. These environmentally acceptable slurry guar products in particular showed improved polymer suspension properties as well as having less than 10% price difference of the mineral oil-based product.
Another major contributor to the hexane extractables was the defoamers. Multiple non-toxic and biodegradable defoamers were evaluated In general, defoamers contain considerably more than 29 ppm of extractable material and that only one defoamer was found to have less than 5.0 mg/l HEM. The non-hexane extractable defoamer product was found from a specialty food additives company.
Although biocides and surfactants contained some HEM, their major contribution was to both high toxicity and poor biodegradability. In the case of biocides, a different mode of cellular toxicity was needed. An appropriate replacement product, based on amino acid chemistry, was found in the cosmetics industry. In addition to having the appropriate kill times, these new biocide products acted as gel stabilizers at fluid temperatures of approximately 175°F (80°C) to about 250°F (121°C). The bi-functionality of these materials also eliminated the use of thiosulfate gel stabilizers until about 250°F.
In the case of surfactants such as water wetting, non-emulsifier and clay stabilizer products, "green" chemistry was readily available. Standard testing verified that they would be equal to or better than the original additives. Additionally, because these new environmentally acceptable water wetting surfactant and non-emulsifier components were used in bulk in the food and cleaning industries, the cost of each was within approximately 5% of the old components.
The company also developed a new family of fracturing fluid breakers to help replace potentially hazardous oxidizers, and they turned out to be much less expensive than high-temperature and high-pH (extremozyme) enzyme breaker products. The newly developed breaker chemistry is based on the use of naturally occurring food substances that are well known and widely used in bulk quantities. The new gel breakers, whose working temperature ranges from about 125°F (52°C) to 280°F (138°C), cost only slightly more than oxidizers.
Gulf of Mexico applications
Three frac pack treatments using the new fluid were performed on gas wells in South Marsh Island and Main Pass. The wells averaged 12,000 ft (3,650 m) in depth with pore pressure of 9.5 ppg (1.14 sg) and bottomhole temperature of 200°F (93°C). The fluid system mixed and pumped with standard mixing equipment and provided the desired fluid rheology for the tip screen-out design. The treatments had net pressure gains of 500 to less than 1,000 psi (3.5 to less than 6.9 MPa). One of the wells is flowing at greater-than-expected rates with 100 psi (0.7 MPa) drawdown across the completion. The operator was pleased that the fluid system fit its corporate mandate to comply not only with the letter but also the spirit of environmental regulations.
At the same time, four wells with eight completions were treated in High Island 365 near the Flower Garden Banks, a reef structure consisting of a pair of topographic features that rise to within 60 ft (18.3 m) of the surface. The features are topped by reef-building corals, fish and a variety of marine organisms. This area was designated as a National Marine Sanctuary in 1992. The use of the new fluid system to treat these wells to helped the operator to minimize the environmental risks of completion operations.
The eight completions were conducted in Block High Island 365, Wells A-8, Upper and Lower; A-12, Upper and Lower; A-21, Upper and Lower; and A-24, Upper and Lower.
The wells averaged 5,000 ft to 7,000 ft (1,500 m to 2,100 m) measured depth; 4000 ft to 5,000 ft (1,200 m to 2,100 m) total vertical depth (TVD) at approximately 130°F (55°C). The reservoir pressures varied from 2,200 psi to 2,600 psi and were perforated at intervals ranging from 20 ft to 50 ft (6 m to 15 m) TVD. The frac packs yielded 50 psi to 400 psi net pressure gains for the 2 by 105 psi modulus rock. The production from the wells met or exceeded expectations. The total production increase was 29 MMcfd
(8.2 by105 m3/day) and 1,000 b/d of oil (178 m3/day). The low environmental impact of the fluid provided the operator with the fracturing fluid and environmental performance it needed to discharge fluids according to its rigs' discharge permits.

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