Residue-Free Fracturing Fluid Provides Superior Cleanup and Exceptional Proppant Transport

Schultheiss, Nathan; Fontenelle, Lucas; Welton, Thomas

doi:10.2118/165128-ms

Cited by 14 publications

(5 citation statements)

References 12 publications

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“…At the described conditions, the LRF retained 78% of the baseline conductivity; at 250°F, a borate-crosslinked guar gel was also tested at the same conditions, retaining 16% of the baseline conductivity to water. These results clearly show that the LRF cleans up very well after breaking and has a higher performance in conductivity regain because of a decreased amount of insoluble residues (Schultheiss et al 2013).…”

Section: • Viscosity Retained Conductivitymentioning

confidence: 67%

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Implementation of Low-Residue Polysaccharide Fracturing Fluid System Aids Flowback Recovery at Chicontepec Basin: Field Experiences on Sandstone Tight-Oil Wells

et al. 2015

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Low-energy and compartmentalized reservoirs make flowback more difficult than in conventional reservoirs following massive fracturing treatments. Conventional guar-based fracturing fluid systems can cause additional skin damage to the fracture because of fluid residues. Low-residue polysaccharide-based fracturing fluid systems, compared to conventional systems, provide a smaller residue percentage according to laboratory tests, and this result agrees with flowback data from wells discussed in this paper. Costs in primary treatments associated with operational events, such as flowback time, can be considerable for well completion operations. Guar-based fracturing fluid systems were used at the beginning of this basin study. After analyzing flowback and early production data, it was decided to change to a low-residue polysaccharide-based fracturing fluid system and to maintain other variables constant, such as injection rate, proppant concentrations, and treatment schedules, to compare fluid performances, cost benefits, and post-stimulation production rates.This paper summarizes results for 70ϩ fracture stages in 30 wells, with an average of 150,000 gal of clean volume per stage and 250,000 lbm of proppant. Guar-based fluid fracturing systems comprise 25% of this study with an average flowback time of 231 hours with 30% (at most) fluid recovery. On the contrary, 75% of the treatments used a low-residue polysaccharide-based system, which required an average of 110 hours of flowback time, while only 10% of the volume was recovered to deliver to production facilities because of the lack of water percentage.Metal-crosslinked low-residue polysaccharide-based fluids are more sensitive to shear stress than borate-crosslinked conventional systems, and they can become unstable at high injection rates and reduced pipe diameters (3 1/2-in. tubing). Increasing tubing friction requires more hydraulic power to apply the same amount of net pressure at the fracture. According to the diameter restriction, this study includes pumping through pipes with diameters larger than 5 1/2-in., therefore making sensitivity to shear stress a nonissue.Low residue polysaccharide-based fracturing systems represent an early production alternative for massive fracturing treatments because of their low residue percentage. These fracturing systems can be

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Section: • Viscosity Retained Conductivitymentioning

confidence: 67%

“…Table 3 shows that, under these conditions, the LRF fluid proppant pack retained 78% of the baseline conductivity at 250°F and 92% at 160°F, respectively (Schultheiss et al 2013). …”

Section: Low-residue Polysaccharide Implementationmentioning

confidence: 94%

Implementation of Low-Residue Polysaccharide Fracturing Fluid System Aids Flowback Recovery at Chicontepec Basin: Field Experiences on Sandstone Tight-Oil Wells

et al. 2015

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“…Studies show that the res-free system cleans up better than borate-crosslinked guar systems, providing higher regained permeability and conductivity in proppant packs. It also provides comparable proppant transport and stability up to 275°F (Welton et al 2013). The purpose of this study is to demonstrate that using the res-free system during hydraulic fracturing treatments can help positively impact production.…”

Section: Res-free Vs Guarmentioning

confidence: 99%

Production Comparison of Hydraulic Fracturing Fluids in the Bakken and Three Forks Formations of North Dakota

Fry

Paterniti

2014

SPE Western North American and Rocky Mountain Joint Meeting

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There have been extensive efforts to recover oil from the Bakken formation in North Dakota since it was discovered in 1951. However, these efforts were not particularly profitable until the 2000s when horizontal drilling and large, multistage hydraulic fracturing treatment methods were used. The new drilling and completions methods created a substantial increase to production, which escalated throughout recent years and created a demand for better, more efficient completions. One major component of these completions is the base fluid used for hydraulic fracturing treatments. This paper compares hydraulic fracturing treatments of a new, residue-free (res-free) hydraulic fracturing fluid to all other fracturing fluid treatments.The res-free fluid system was presented in 2012 as a premier fracturing fluid and economic alternative to guar-based systems to increase the resultant fracture conductivity. Since 2012, more than 40 wells have been completed in either the Bakken or Three Forks formations of North Dakota using the res-free fracturing fluid. While initial cost savings were realized, the production results from these wells have not been extensively studied. This paper presents the findings of a study comparing production from wells treated with res-free fracturing fluid to wells treated with other hydraulic fracturing fluids.Because the wells completed using the res-free system are widespread throughout North Dakota and belong to several different operators, choosing a specific study area was challenging. To overcome this challenge, a spatial sampling technique was used. Spatial sampling is a method for comparing a large group of wells to their direct offsets. For this study, spatial sampling was applied to compare wells completed using the res-free system to wells completed using other fluids. To normalize general completion methods, only wells completed since the beginning of 2012 are included in this study. Offset wells for this study are those within a 1-mile radius from the center well. The production data for all wells was obtained from public sources. The proppant amount and total fluid volumes were normalized per foot of lateral to minimize variables. Other factors, such as drilling placement, type of proppant, type of fluid, or compartmentalization can affect production; however, these effects are not considered during this study.

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“…Final permeability of the core was measured again using a 7% KCl brine solution at a flow rate of 5 mL/min at 250°F. Schultheiss et al (2013) provide a description of this test method, as well as a flow diagram of the test cell. Table 2 summarizes regained permeability results for the control res-free fluid and standard guar fluid formulations compared to the res-free S fluid.…”

Section: Regained Permeabilitymentioning

confidence: 99%

“…As the data illustrates, there is virtually no difference in the formation-damaging characteristics of the res-free fluid system when prepared in the synthetic-produced water. Schultheiss et al (2013).…”

Section: Regained Permeabilitymentioning

confidence: 99%

Effects of Alternative Water Sources on Formation and Proppant Pack Damage Reduction Properties of Near-residue-free Fracturing Fluid

Russell

Singh

Schnoor

2014

SPE International Symposium and Exhibition on Formation Damage Control

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This paper examines how the use of high-salt-content waters (i.e., produced and flowback water) in conjunction with a recently developed, virtually residue-free (res-free) hydraulic fracturing fluid affects the cleanup properties of the system. The res-free fluid system is designed based on a naturally low residue polymer that, when breaking, causes significantly less damage to the formation and proppant pack compared to conventional guar-based fracturing fluids.Since its introduction, guar-based fluid technology has grown to dominate the hydraulic fracturing industry because of its reliability and cost-effectiveness. However, guar gum contains a significant amount of insoluble residue that is not removed during its processing. The residue can cause damage to both the proppant pack and hydrocarbon-bearing formation when the broken fluid is flowed back following the fracturing treatment. This damage can impair hydrocarbon flow from the formation and through the propped fracture, resulting in lower production over time. The res-free fluid offers better cleanup when breaking than guar-based fluids; therefore, it offers significantly higher proppant pack conductivity and formation permeability in laboratory testing.The res-free polymer exhibits sensitivity to certain ions present in the solution, both in terms of gel hydration and crosslinking behavior. Depending on the ions present in the water and their respective concentrations, manipulation of the crosslinked res-free fluid system chemical formulation can mitigate these effects and achieve a stable, highly viscous fluid suitable for hydraulic fracturing. This paper investigates whether the necessary reformulations impact the regained permeability and conductivity of the fluid system. Rheological data demonstrating how the reformulated fluid compares to standard formulations is presented. Additionally, test results are presented highlighting the effects of alternative water sources on res-free fluid regained permeability and conductivity data.The use of produced and flowback waters for fracturing operations can substantially reduce both the economic and environmental impact of fracturing operations. The combination of the res-free fluid's ability to use these water sources and its excellent damage-reducing properties provides a system with significant advantages compared to conventional technologies in many applications.

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Residue-Free Fracturing Fluid Provides Superior Cleanup and Exceptional Proppant Transport

Cited by 14 publications

References 12 publications

Implementation of Low-Residue Polysaccharide Fracturing Fluid System Aids Flowback Recovery at Chicontepec Basin: Field Experiences on Sandstone Tight-Oil Wells

Implementation of Low-Residue Polysaccharide Fracturing Fluid System Aids Flowback Recovery at Chicontepec Basin: Field Experiences on Sandstone Tight-Oil Wells

Production Comparison of Hydraulic Fracturing Fluids in the Bakken and Three Forks Formations of North Dakota

Effects of Alternative Water Sources on Formation and Proppant Pack Damage Reduction Properties of Near-residue-free Fracturing Fluid

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