Advanced frac fluid chemistry helps boost Wolfcamp IP rates

Reducing the friction factors that can restrict sufficient pumping rates, required for uniform proppant transport, represents a prevailing challenge for high-rate hydraulic fracturing operations. Typically, operators have relied on multi-additive methodologies that increase both the complexity and costs of frac programs designed to stimulate tight-margin unconventional assets.

More recently, the application of a dual-function high-viscosifying friction reducer (HVFR) polymer in the Permian basin’s Wolfcamp shale has demonstrated efficacy at delivering high pump rates and transport capacity, without the need for cross-linked or linear gel additives to provide viscosity for particle suspension. Specifically, a comparative analysis of Wolfcamp offsets shows that the proprietary HVFR polymer has helped increase pumping rates 20% to 25%, with up to 6 lb/gal of frac sand. The analysis also shows that it has helped increase initial production (IP) rates by up to 30%, compared to conventionally fraced wells.

The patent-pending polymer was engineered to reduce pressure and improve the transfer of energy, from horsepower on the surface, to the hydraulic fractures. Owing to increased average pump rates, the new-generation HVFR polymer effectively distributes proppant further into the fracture network at lower velocities, improving flow capacity and, in turn, the potential for sustainable reservoir drainage.

The recently formulated HVFR polymer represents an advancement in hydraulic fracturing fluid technology, because it helps close the gap between pressure reduction, horsepower, and frac sand transportation and distribution. The chemically-driven methodology has resolved many of the intrinsic limitations of cross-linked, slickwater and complex hybrid frac systems.

PROPPANT TRANSPORT ISSUES

According to IHS Markit¹ and other industry analysts, U.S. frac sand consumption was expected to reach new heights in 2017, surpassing the previous high-water mark of 2014. More to the point, in its Aug. 1, 2017, quarterly earnings call, leading sand producer U.S. Silica, which estimates frac sand usage has increased 70% over the past four years, predicted 2018 demand will hit 90 million tons or greater. Of that, 45% would come from the Permian basin, with 85% of the increased deliveries comprising finer-grade 40/70- and 100-mesh proppant, the company said. Record frac sand consumption coincides with the trend toward appreciably longer horizontal laterals, increased frac stages and proppant loadings of between 2,000 to 5,000 lb/lateral ft. The proportionately higher frac fluid volumes introduce increased pressure and friction values, typically higher in the toe section and decreasing as the fracing operation progresses toward the heel.

Unprecedented proppant volumes have re-energized attention on carrier fluids capable of optimizing proppant distribution to enhance overall stimulation efficiency and maximize EUR.^2,3,4,5 As the industry has drawn a direct correlation between sand volumes and production, sustained conductivity and proppant placement remains among the most daunting issues confronting the unconventional sector. Unlike conventional formations, which experience more benefit from long-fracture half-lengths, impermeable zones perform best when surface area exposure is maximized through the creation of a complex dendritic fracture network. The use of thin fracture fluids—pumped at high rates—helps maximize complexity, while pumping small-grained proppant enables entry into micro-fractures that are inaccessible to large-grained particles.

Noting that effective placement of proppant in a fracture has a dominant effect on well productivity, Blyton, et al,³ hold that existing fracture models assume ideal proppant transport, even with low-viscosity fluids, and that often they were found to over-predict propped or effective lengths by 100% to 300%. More specifically, it is commonly assumed that the average proppant velocity due to flow is equal to the average fluid velocity, while the settling velocity calculation relies solely on Stokes’ Law, which simply describes the force of viscosity on a small sphere moving through a viscous fluid.

CROSS-LINKED VS. SLICKWATER FRACS

Accordingly, owing to their highly viscous characteristics, cross-linked polymers were introduced into hydraulic fracturing to increase the volumetric loading of the sand and to build fracture width and dimensions. Cross-linked polymers traditionally have been integrated in frac designs to hold the sand in total suspension, and to improve lateral proppant distribution (fracture half-length) at low velocities. Cross-linking generally is described as a bond formed between polymer chains, either between different chains or between different parts of the same chain. To create the viscous fluid, cross-linked gel systems normally combine a guar or modified guar-based fluid with borate, zirconate, titanate or other reagents in the presence of alkali.

Though cross-linked fluids provide superb suspension and may deliver high proppant pack flow-capacity after cleanup, they come with higher cost and operational complexity. Ironically, the intrinsic suspension benefits of high viscosity prove detrimental, in that the viscous nature of cross-linked polymers generates higher pumping pressure, requiring the frac fluid to be pumped at reduced rates to manage pressure. The economic issues are compounded with the required high concentrations of costly biopolymers, such as guar, which has a history fraught with a supply-demand imbalance. In addition, cross-linked polymers require breakers to dissolve the polymer bond once pumping is completed. While cross-linked polymers function satisfactorily in fresh water, the corresponding low tolerance for chlorides or solids within the carrier fluid severely complicates water recycling and negatively affects operators’ environmental profile.

As the industry has evolved, and as unconventional assets have become primary targets, a noticeable shift in the use of slickwater frac systems has occurred. Traditional slickwater treatments incorporate an anionic or cationic polyacrylamide-based polymer to keep the fluid in the appropriate flow regime, and to act as a friction reducing agent, enabling maximum fluid flow at minimum pumping energy.⁶ Since the wide-scale adoption of hydraulic fracturing, slickwater fracs that incorporate friction reducers have been in vogue as a mechanism for improving pump rates and reducing pressure, to stay within the limits of the casing. The primary drivers for this methodology are reduced costs, minimalized proppant pack damage, increased fracture complexity and a comparatively lowered environmental footprint. The capacity to withstand an extensive variety of fluid conditions, while maintaining an acceptable level of pressure control, also clears the way for the recycling of higher volumes of flowback and produced water. 

However, the diminished capability of these thin fluids to effectively suspend and transport proppant in a fracture (and the wellbore) poses the most significant limitation to slickwater frac designs.⁷ Exceptionally low viscosity requires increased pump rates to maintain the turbulence needed for particle transportation. While turbulence can be regulated easily when volumes and velocities are of a known value, such as within the casing, it becomes much less predictable when the fluid exits into the reservoir, and velocity rapidly dissipates.⁸ Weakened velocities can dramatically alter the ratio between sand and water, thus limiting proppant distribution and ultimately the generation of effective half-lengths.

To compensate for the low viscosity and limited carrying capacity of slickwater treatments, best practices typically dictate lower proppant concentrations (3 lb/gal or less) and the use of large volumes of finer mean particle diameter proppant, most commonly 100-mesh and 40/70 mesh. What’s more, water recyclability is offset partially by record water consumption/well, as sand volume/lateral ft continues to spiral to accommodate the reduced sand-to-liquid ratio.

DUAL-FUNCTION METHODOLOGY

Attempts to capture the respective functions of slickwater and cross-linked gel frac systems in a single well led operators to employ so-called hybrid fracs.^9,10 Defined as a mix between slickwater and cross-link-type treatments, hybrid fracs transition from slickwater polyacrylamide polymers to a slickwater polymer with a guar-based linear gel viscosifier. The linear gel is used to increase viscosity to improve the ability to transport proppant away from the near wellbore (NWB) region. If necessary, a cross-linked gel can be pumped at the tail end of the treatment to permit higher proppant concentrations, and to promote a conductive fracture network, specifically in the NWB region.

Complex hybrid fracs require a higher level of project management, because of the multiple polymers that must be added and replaced throughout each of the stages, where concentrations reach as high as 20 lb/1,000 gal. Consequently, issues relating to the compatibility of the various polymers, breaker requirements and chloride tolerances can vary significantly, requiring careful control of not only the chemical compositions and loadings, but also of the base water and the individual mixing requirements. As such, adding multiple polymers together can drive the water pumping cost, per 1,000 gal, into the $80-plus range. Broken down, required dosage rates call for 1 to 2 gal of friction reducer/1,000 gal of water, at a cost of $6 to $10/gal, and the viscosifier rate varies from 18 to 20 lb/1,000 gal of water, or 4 to 5 gal of viscosifier/1,000 gal of water at a cost of $15–$25/gal.

Operators also have turned to increased dosage rates of standard polyacrylamide friction reducers to build viscosity and improve particle transportation. Although this can be an effective approach, polyacrylamide loadings of more than 6 gpt can be required (depending on water quality) to achieve viscosity levels comparable to that of a 10- to 15-lb guar-based linear gel. Consequently, it became clearly evident that the higher dosage ratio of even the cheapest polyacrylamide often yields negligible economic benefit, with costs often comparable to that of a hybrid frac.

To better control the economics and meet operational objectives, operators have incorporated emerging high-viscosifying friction reducers (HVFR) in frac designs to allow dual functions within the same polymer. With reservoir compatibility, and minimizing the amount of solids pumped during a frac among the primary justifications for development, low-solids polymers can replace the multiple-chemical blends previously used, reducing both volume and mass. Essentially, HVFR technology improves proppant transportation, while reducing pumping pressure or horsepower requirements during pumping operations. Since their debut, HVFR’s have reduced the volume of solids/1,000 gal of water at an average 25% of the cost of a hybrid frac.

QUALIFICATION OF NEW HVFR

Fig. 1. Simply elevating the dosage ratio of the HVFR polymer, as sand concentration and proppant density increase, delivers gelled fluid viscosity characteristics.

Conceptually, development of the new-generation HVFR-1405 polymer stepped beyond the circular reasoning of particle transportation, based on the slip velocity of a solid within a viscous fluid. More focus was placed on advancing frac fluid chemistry to develop an enhanced transport fluid. The new-generation polymer has since allowed operators to seamlessly transition from slickwater to gelled fluid characteristics, with the same chemistry, by simply elevating the dosage ratio, as the sand concentration and particle size increase, Fig. 1. The polymer functions by creating a drag coefficient between the sand and the moving body of fluid, sufficient to enable the sand to be progressed with the fluid without separation. The shear sensitivity of the polymer provides stable pressure reduction, even as loading ratios are varied.

During initial polymer development, best-in-class polyacrylamides were used to establish test loop pressures and rate baselines. At the same time, it was determined that a method was required to test and record data from actual jobsites. The ultimate objective was verifying particle transport efficiencies in low-velocity conditions, while improving hydraulic horsepower requirements. Accordingly, a closed-loop system was warranted, where control variables could be quantified and recorded, and polymer loading data could be compared to particle transport efficiencies, while measuring thermal thinning, chloride levels, pH shifts and hydraulic horsepower.

Computer-controlled, steady-state polymer delivery systems were designed and deployed for data collection. This pressure loop data was then compared to known values during plug drill-outs with 2-in. coiled tubing strings of an average length of 20,000 ft. The closed-loop system used during the drill-out process was identified as the ideal post-development test lab to evaluate and refine the polymer.

Drill-outs are among the most challenging aspects of a completion, as the operator is working with small-diameter tubulars, generating high friction while removing large solids from the wellbore, at velocities much lower than those in a hydraulic fracturing job. Additionally, the recirculation and dilution of flowback during drill-outs affects water quality unfavorably. The ensuing challenges required the polymer be sufficiently shear-sensitive in order to reduce pressure, while also developing ample viscosity to prevent the fluid from separating from the solids.

With the drill-out trials establishing the variables that control particle transportation efficiencies, adjustments to the polymer design were carried out over four years in more than 3,500 drill-outs. Overall, the resulting efficiencies in particle transportation reduced well time and lowered chemical consumptions, while also eventually eliminating short trips.

FIELD RECAPS

Fig. 2. Planned Wolfcamp treatment with a slickwater frac, using only a standard polyacrylamide friction reducer.

General observations from field operations have shown a notable improvement in the ability to place proppant with relatively small increases in viscosity. Utilizing a standard linear gel measurement at 511 sec-1 as a baseline and increasing the viscosity from typical friction loadings of about 2 cp to a minimum of about 7 cp—by use of a viscosifying agent—has resulted in a significant improvement in the ability to place proppant and increase concentrations.

Figure 2 shows the overall treatment plot for a Wolfcamp B frac in Reeves County, Texas. As shown, efforts to place the treatment, using only slickwater and a standard polyacrylamide friction reducer, were met with consistent resistance, once the 40/70 proppant concentration reached 1.25 to 1.50 lb/gal. Based on the observed pressure responses, the treatment schedule was augmented with multiple unplanned sweeps, but the proppant concentration remained limited to 1.5 lb/gal. At approximately 190 min. into the treatment, a 15-lb linear gel was pumped, and after that, formation clean-up was observed, and pressure was stabilized. From then on, the 40/70 proppant was stepped up successfully to 3.0 lb/gal concentration without incident. This treatment successfully placed 448,000 lb of 100-mesh and 40/70-mesh frac sand, using 12,075 bbl of fluid over the course of 240 min.

Fig. 3. Proactive linear gel treatment used to increase viscosity of the subject Wolfcamp well.

Based on the positive response to the viscous fluid, the decision was made to proactively start the linear gel immediately (Fig. 3) following the 100-mesh proppant. Figure 4 shows how the slickwater and friction reducer were replaced during various parts of stage 11, where the friction reducer was pumped at 70.9 min. at a dosage rate of 3.75 gpt, with no improvement on pressure. At 80 min. into the stage, the HVFR polymer was introduced into the system and ramped up to an identical dosage rate, with marked improvement in both rate and pressure.

At 100 min. into stage 11, the linear gel was brought back online at a dosage rate of 4.5 gpt (15 lb linear gel) as the sand was being ramped up to 1 lb/gal, with a noticeably negative impact on both rate and pressure. At 155 min. into the stage, the 4.5-gpt (15-lb) linear gel was again replaced with the HVFR-1405 polymer at a dosage rate of 1.5 gpt, resulting in improvements in rate and pressure. Correspondingly, the sand concentration was raised to 1.75 lb/gal. Hence, the new-generation polymer demonstrated the capacity to move higher lateral sand volumes at significantly lower dosage ratios. Additionally, a comparative analysis shows incremental oil production averaging 25% to 30% for Wolfcamp wells treated with the HVFR polymer.

Fig. 4. The addition of the HVFR polymer in Stage 11 of one Wolfcamp well demonstrated noticeable improvements in both rate and pressure.

It remains a matter of conjecture whether the comparatively improved performance can be attributed to enhanced sand placement or improved conductivity, due to the cleaner breaking of the polymer and the absence of precipitate generated. However, the enhanced production likely can be explained by considering the retained conductivity values generated by the new-generation polymer, compared to that of a standard linear gel or cross-linked polymer, Table 1. As detailed in the table, the combination of the shear thinning nature of this material and cleaner breaks exhibited a 70% improvement in retained conductivity, compared to a cross-linked polymer.¹¹

It also stands to reason that using the polymer at a concentration of 6 lb/1,000 gal would be less damaging to the formation, rather than using 20 lb/1,000 gal of linear gel or cross-linked polymer. Although sand placement and horsepower transfer are critical components to a well’s performance, reducing the amount of damage to the porosity and permeability generated by the sand is equally important.

 
Similar responses to pumping a HVFR polymer-enhanced viscous fluid have been observed in the Eagle Ford, Haynesville, Marcellus, Niobrara and other unconventional plays. While treatment character will vary on a well-by-well and even stage-by-stage basis, options are available to help improve proppant placement and operational efficiency. Likewise, reducing plugging clears the way for optimizing many of the variables and mitigating the limitations associated with the frac design to focus on what best maximizes well production.  

REFERENCES

1. Jacob, T., “Frac sand demand expected to exceed peak 2014 levels,” IHS Markit Energy Blog, May 3, 2017.
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3. Blyton, C. A., D. P. Gala and M. M. Sharma, “A comprehensive study of proppant transport in a hydraulic fracture,” SPE paper 174973-MS, presented at the 2015 SPE Annual Technical Conference and Exhibition, Houston, Texas, Sept. 28–30, 2015.
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9. Handren, P., and T. Palisch, “Successful hybrid slickwater-fracture evolution: An East Texas Cotton Valley Taylor case history,” SPE Production and Operations, August 2009.
10. Sharma, M. M., P. B. Gadde, R. Sullivan, R. Sigal, R. Fielder, D. Copeland, L. Griffin, and L. Weijers, “Slickwater and hybrid fracs in the Bossier: Some lessons learnt,” SPE paper 8876-MS, presented at the 2004 SPE Annual Technical Conference and Exhibition, Houston, Texas, Sept. 26–29, 2004.
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