Friction reduction polymer aids slickwater fracs in the Haynesville

The Haynesville shale formation, centered in northern Louisiana, is located at depths from 10,500 to 13,500 ft (3,200 to 4,115 m). Wells in this region have an average total vertical depth of 11,000 ft (3,353 m), with a lateral section that can reach out an additional 6,000 ft (1,830 m). At these depths, downhole environments can be harsh. For the Haynesville, bottomhole temperatures can reach 380?F (193?C) with average temperatures around 315?F (157?C). Along with temperature comes high pressure. Average treating pressures in the Haynesville can range from 6,000 to 15,000 psi.

Successful workover operations using coiled tubing as well as slickwater frac operations require a viable friction reducer throughout the process. An adequate friction reducer can assist operations by reducing friction pressure, allowing higher pressures from the same number of pumps for fracing operations. For coiled tubing operations, it also improves HSE and offers substantial cost savings for workovers.

First commercialized in 2008, Drilling Specialties Co.’s HE 150 Polymer reduces friction in both coiled tubing operations and slickwater fracs. The polymer is temperature-stable to 400?F (204ºC) in most monovalent and calcium chloride brines. In heavier brines such as calcium bromide and zinc bromide, it is thermally stable to 300?F (149?C). The high-viscosity synthetic polymer is useful in thickening hydrochloric acid, brines, or freshwater. It maintains high temperature stability, yet maintains efficiency by producing more viscosity with each pound of polymer.

The Liquid HE 150 Polymer is a suspension of the polymer in iso-alkane oil, which is 45% active with a density of 8.2 lb/gal and an activity of 3.6 lb/gal. The polymer is designed for easy handling even in severe winter conditions – the suspension maintains a pour point below -30?F (-34?C). The polymer also features rapid hydration. Test results show complete viscosity development in 2% KCl within one minute at 75?F (24?C), which suggests the polymer’s potential use in continuous mix applications such as slickwater fracturing treatments. The polymer’s formulation is derived from Drilling Specialties’ other polymer suspensions, which have been used for more than a decade. The polymer has proven to be stable with no indication of particle settling or phase separation for more than a year under normal storage conditions.

Typical setup of a slickwater frac includes a pump truck (two pumps rated at 15,000 psi); coil truck (17,000 ft 2-in. CT); injector unit; X-mas tree; manifold/choke operator unit; and inflow frac tanks. (Images courtesy of Drilling Specialties Co.)

Slickwater friction reduction
Many slickwater fracturing treatments use a polyacrylamide emulsion polymer (PHPA), which is added on the fly. While PHPA remains relatively inexpensive, it poses certain limitations. As an invert emulsion additive, complete inversion of the emulsion must be achieved before the polymer can perform to reduce drag; this can be problematic in some field brines. Incomplete inversion leads to lower achievable pump rates due to higher friction pressure. The problem can be rectified by using a co-surfactant. This adds another component to the system. PHPA also can be sensitive to brine components and contaminants, particularly multivalent cations (Ca+2, Mg+2, Fe+3, etc.). These cations can attach to the hydrolyzed (carboxylic acid) portion of the polyacrylamide, resulting in crosslinking and loss of solubility.

As a friction reducer, HE 150 Polymer readily disperses when added to water, so lumping is avoided. One distinct advantage of the HE 150 Polymer suspension is that it does not require an inversion to expose the polymer to frac fluid like the emulsion polymers do. As a result, common water contaminants do not tend to interfere with the rate of viscosity development.

The polymer is a more efficient friction reducer than polyacrylamide, so lower concentrations of polymer produce the same results normally expected from PHPA. The Liquid HE 150 Polymer suspension delivers more active polymer (3.6 lb/gal) than a typical emulsion polymer (2.6-3 lb/gal), so it should require less volume to produce the same results. The process is simple. Start a slickwater fracturing treatment with 25% less volume than when using traditional emulsion polymers. Adjust the concentration up or down to maximize the injection rate. The Liquid HE 150 Polymer is an oil-based suspension with low-bulk viscosity, making it relatively easy to meter into a fluid stream, even in winter weather. For environmentally sensitive areas like the Gulf of Mexico, Greenbase HE 150 Polymer is an available alternative.

Polymer cleanup
Particularly in completions applications, concerns often arise regarding how to remove residual polymer from the near-wellbore area after the operations are finished. The HE 150 Polymer is a robust polymer that remains soluble and does not degrade under normal conditions, making it generally useful in the oil field. It can, however, be degraded under downhole conditions. It can be removed with solutions of commonly used oilfield oxidizing agents such as ammonium persulfate.

Reducing circulating pressure
As part of the company’s harsh environment polymers line, HE 150 Polymer is being used in areas like the Marcellus, Eagle Ford, and Haynesville shales. Several operating companies are seeing higher returns on investment.

HE 150 Polymer readily disperses when added to water, so lumping is avoided. The suspension does not require an inversion to expose the polymer to frac fluid, like the emulsion polymers do. As a result, common water contaminants do not tend to interfere with the rate of viscosity development.

Liquid HE 150 Polymer was used to reduce the circulating pressure of a 10 lb/gal brine in the Haynesville shale. The operator used a 2-in. coiled tubing (CT) unit to drill out perforation plugs. The tapered CT string consisted of 1.65-in. (inside diameter) to 10,000 ft (3,048 m); 1.624-in. from 10,000 to 14,000 ft (3,048 to 4,267 m); and 1.594-in. from 14,000 to 17,000 ft (4,267 to 5,182 m) through a 5.5-in. casing.

The project used baseline brine with a weight of 10 ppb to a depth of 12,300 ft (3,749 m). The pump rate was 2 to 2¼ bbl/minute. The circulating pressure was 7,408 psi with a wellhead pressure of 5,500 psi. Operating temperatures ranged from 330°F to 340°F (166?C to 171?C).

The Liquid HE 150 Polymer was premixed in 10 bbl increments with the brine (although not required) with a temperature of 92°F (33?C). To reduce friction, the polymer was loaded at a rate of 1.5 to 2 gal/10 bbl of brine. According to field personnel, the polymer mixed well, producing a smooth uniform brine. Additionally, a “sweep pill” was pumped using a half gallon of polymer per 1 bbl of brine (5 gal Pail/10 bbl) and produced a uniform viscose sweep.

After treatments of Liquid HE 150 Polymer, the well’s circulating pressure was 6,110 psi with a wellhead pressure of 4,720 psi, which was the best overall psi decrease observed. Overall circulating pressure decreased by 1,000 to 1,298 psi. Mixing materials required for this job were reduced by approximately 50% with an overall material cost savings of 30%.

A similar project, also in the Haynesville, reduced circulating pressure of a 9.8 lb/gal brine at a depth of 12,500 ft (3,810 m) pumping 2 bbl/minute. The original circulating pressure was 7,395 psi with a wellhead pressure of 5,480 psi. The Liquid HE 150 Polymer was premixed in 10 bbl increments with the brine at a temperature of 94°F (34?C). Liquid HE 150 Polymer loading was 1gal/10 bbl of brine for friction reduction.

After treatments with HE 150 Polymer, the circulating pressure was reduced to 5,990 psi with a reduced wellhead pressure of 4,680 psi. Overall circulating pressure was decreased by 1,200 to 1,405 psi with a ratio of 420 gallon brine to one gallon liquid polymer mixing ratio.

According to field personnel, the polymer mixed well with no fish eyes, and the product had no phase separation in the pail. In addition to improving the temperature and pressure conditions, the company also benefited from widespread cost efficiencies from reduced mixing volumes and reduced material costs.