Aggressive Stimulation Design Yields Better Returns
The authors examine methods of adopting an aggressive approach to optimizing stimulation design to lower the break-even level of operations and evaluate the results.
The authors examine methods of adopting an aggressive approach to optimizing stimulation design to lower the break-even level of operations and evaluate the results. Operators achieved significant improvements in production by changing parameters in the fracturing and completion design strategy, including, but not limited to, the amount of water used, the amount of sand pumped, stage spacing, maximum sand concentration, and fracturing-fluid selection. The complete paper addresses the importance of aggressive design, its evolution, and its enabling technologies.
Trends in Development of Unconventional Resources
Although completion practices and production numbers vary from basin to basin and from play to play, certain high-level trends remain in the development of unconventional reservoirs over the past few years. In most places, operators have been drilling increasingly longer laterals. Although public fracturing-stage-count information is scarce, internal service-company data still show a continuous increase in stage count and, in certain plays, an increase steeper than the increase seen in perforated intervals. Cased-hole completions with more than 50 stages per well are becoming common in all basins, thanks to the improved efficiency of fracturing and plug-and-perf operations.
At the same time, fracturing treatment sizes have grown even faster than have perforated intervals and stage counts. Median proppant volumes have nearly tripled during the past 5 years. The stimulation fluid volumes increased nearly proportionally to proppant volumes. Slickwater (SW) has become a fluid of choice in most plays, thanks to its operational simplicity and low cost. Hybrid treatments also remain popular; in these approaches, a high-viscosity crosslinked fluid, usually guar-based, often is pumped at the end of a treatment to deliver higher proppant concentrations and effectively prop the near-wellbore area. The number of higher-cost and operationally more-complex crosslinked fluid-fracturing jobs has decreased as placement of large amounts of proppant with crosslinked jobs becomes uneconomical.
Longer laterals, better wellbore coverage, and significant amounts of fracturing materials enable increased well productivity in most plays. Production here is expressed in barrels of oil equivalent, calculated on the basis of relative cost, with 20 Mscf equal to 1 bbl of oil. Median production volumes, normalized by 1,000 ft of perforated interval, still demonstrate substantial increase over time. However, with production normalized by 1,000,000 lbm of proppant, or by proppant density per perforated interval, the trends turn negative, indicating diminished returns with further increase of proppant volumes per well.
In addition to reservoir depletion and sweet-spot exhaustion with lower reservoir and completion quality available for new wells, one of the major factors behind these trends is believed to be infill drilling, a technique becoming a common practice in US plays. It is apparent that the industry is using a brute-force approach, increasing material volume in order to increase production. This approach is unlikely to be sustainable in the long run because diminishing returns from increased fracturing-material volume will eventually negate net profits. However, current availability of major fracturing materials, mainly sand and water, is not likely to be a bottleneck, because lower-quality material sources remain available.
The effects of low-quality fracturing materials on well performance have yet to be understood fully, however, because deteriorated hydraulic-fracture conductivity can affect production. Because the massive-fracturing-job approach is very successful, the industry is focused currently on major-job optimization.
Addressing the Challenge
Rheology. The viscous SW solution, referred to by the authors as High-Viscosity Fluid Reducer 1 (HVFR-1), generates higher viscosity than regular friction reducer at the same concentration. The viscosity of HVFR-1 fluids was measured on a viscometer with different shear rates at 70°F (Fig. 1). As can be observed, 8-gal/1,000-gal (gpt) HVFR‑1 has a viscosity of 38 cp at a shear rate of 511 s–1, whereas 8-gpt regular friction reducer provides a viscosity of only 18 cp. The viscosity of HVFR-1 fluids increases as the concentration increases. At loading of 2- to 4-gpt HVFR-1, the viscosity is comparable to 15- to 20-parts-per-trillion (ppt) linear guar fluids in tap water.
Sand-Transport Capability. Dynamic sand-settling tests were performed to demonstrate the ability of fluids to transport sand inside fractures. Fluids containing 2 lbm of proppant per gallon of fracturing fluid (ppa) of 100‑mesh sand were pumped through a slot flow cell. For 2-gpt regular friction-reducing fluid, a large amount of sand settled at the bottom of the slot, whereas only a small amount of sand settled when 2-gpt HVFR‑1 fluid was used. These results have shown clearly that HVFR-1 fluid shows improved sand-transport capability compared with regular SW fluids with the same loading of friction reducers. The 20-ppt linear guar is slightly superior to the 2-gpt HVFR-1 fluid, but the difference is small. In 4-gpt HVFR‑1 fluid, no sand settled at the bottom of the slot.
Break Test. The broken fluid is water-like, with very low viscosity. One important advantage of HVFR-1 fluid over guar gel is that HVFR-1 easily can be broken with oxidizer breakers with little or no solid residue. However, linear guar gel produces solid residues after breaking. 20-ppt linear guar and 4-gpt HVFR-1 fluids were broken with 1-ppt ammonium persulfate at 150°F for 2 hrs. A large amount of solid residue was observed with broken 20-ppt linear guar, whereas little residue was seen with broken 4-gpt HVFR-1 fluid.
Operators in all basins have proved that increasing job size both with water and sand per stage, increasing pumping rate, and tightening both stage and cluster spacing has delivered sustainable higher production rates than more-conventional fracturing designs. Although the importance of a new aggressive stimulation design has been confirmed, the industry is still far from optimizing fracturing design and identifying the level of proppant volumes and fluid volumes at which the production reaches peak returns.
The complete paper describes the fracturing-design evolution of an operator that eventually adopted an aggressive approach though the use of HVFR-1. A well had been completed with packers, and sleeves with mechanical packers, following a standard fracturing-stage design. The typical design involves pumping 40‑bbl/ft SW and 600-lbm/ft sand with or without sweeps in between sand stages. The SW limits the maximum sand concentration to 1.25 ppa on average. Operators had been experimenting consistently with the design and had explored different pump schedules to create more fracture complexity.
The next phase was common in 2015 to early 2016, when experiments began to extend laterals and increase the number of stages. At that time, typical stage spacing was 230 ft, but sand and water volumes began to show significant increase in consumption to 50 bbl/ft for water and 900 lbm/ft for sand.
In the next distinct phase, which took place at the end of 2017, aggressive design became common practice. Stage spacing was tightened to 150 ft, and much more fluid and sand were used (70 bbl/ft fluid and more than 1,300 lbm/ft sand). These experiments showed markedly improved production over that of previous designs, as well as longevity until production reached a peak and subsequently declined.
The aggressive design was extremely successful and promised better payouts. The only component that has not been modified since was proppant concentration, a modification that would require examining the carrying capacity of fluids. A 1.25-ppa concentration for an SW job would be a typical sand concentration for this type of fluid. Although an increase in concentration would be possible, the fluid would need to be changed to a hybrid or crosslinked fluid, which would raise the risk of introducing commonly known complexities, such as a larger footprint on location and higher risk of service delivery issues during the treatments, which, in turn, may affect net present value for wells. Guar residue would affect proppant-pack conductivity, thus creating more flow restriction and possible damage.
With the success that the aggressive design has brought to the unconventional market in the US, concern has been raised about reintroducing guar-based fluids. The solution came from the chemical industry, which showed that a friction reducer could be manufactured that was able to create viscosity and introduce more sand-carrying capacity over standard friction reducers. The introduction of viscous SW enabled making aggressive designs more extreme by increasing the maximum sand concentration to 3.5–4.0 ppa and increasing sand placement to more than 1,700 lbm/ft.
Validation of the fluid’s ability to transport sand with such a high concentration has been achieved on a few thousand stages. Results are consistent in terms of ease of use, a minimum of service quality issues on location, and a greater payout to the operators over a longer period, with prolonged longevity of production before the peak.
Statistical analysis has demonstrated that basins generally are on the verge of converting operations from crosslinked fluid-fracturing and hybrid-type jobs to SW, and the change pays off with consistently higher production returns. There has been a need for an aggressive completion design in the quest for better wellbore coverage and reservoir contact. The aggressive design includes all parameters in the completion and stimulation strategy; each parameter can have a significant effect on production sustainability.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 191864, “Aggressive or Not? Experimenting With Fracturing Design and Fluids in Pursuit of Better Returns,” by Max Nikolaev, SPE, Haiyan Zhao, Yenny Christanti, SPE, and Sergey Makarychev-Mikhailov, SPE, Schlumberger, prepared for the 2018 SPE Argentina Exploration and Production of Unconventional Resources Symposium, Neuquén, Argentina, 14–16 August. The paper has not been peer reviewed.