Laboratory and Field Trial Data.

Laboratory and field trial evaluations of Propel SSP proppant transport technology are underway and favorable results are being generated. As additional reports and data are generated, we will make them available.

santrol ssp

See below for more field trial data.

Propel SSP has undergone a range of evaluations in Fairmount Santrol and Stim-Lab laboratories to document its baseline properties. This work also points to its expected behavior in a wide range of potential field conditions. We will report on field trial results and actual operating case studies as they become available.

Propel SSP Technology Tail-In vs. Slickwater Simplified Design

Escondido Formation,
Rich Gas Play

Higher IP, improved hydraulic fracturing efficiency

 Escondido map
 

 

An optimized design with higher proppant loading using Propel SSP technology as a 46% tail-in boosted 60-day initial production by more than 55% while decreasing water demand, chemical additives, and pumping time. The smaller-mesh, lower-conductivity frac sand coated with Propel SSP outperformed the larger-mesh, higher-conductivity frac sand, based on the production results, by maximizing the fracture surface area.

  • Improved hydraulic fracturing efficiency
  • Decreased pumping time: 25%
  • Less chemical additives: 15%
  • Decreased water consumption: 10%

60 Day Production Gain_Blue ssp

 

Escondido bars

 

Propel SSP Technology vs. Slickwater

Mississippian Lime,
Liquids-rich Play

Increased recovery

 Mississippian map

 

In a simple, direct comparison between 20/40 Northern White sand in a conventional slickwater design and 20/40 Northern White sand coated with Propel SSP technology, production increased 45% after 18 months.

 

18 Month Production Gain_blue SSP

 

Mississippian bars

 

Propel SSP Technology Tail-In vs. Hybrid System

Marcellus Formation,
Liquids-Rich Gas Play

Increased contact area and conductivity

 Utica map

 

In more complex frac designs that use viscosifiers for transporting large concentrations of coarser proppant sizes, there is always the threat of formation and proppant pack damage. As this case study documents, replacing conventional viscosifying gel with a Propel SSP tail-in can improve initial production.  Propel SSP mobilizes more oil and gas recovery with the additional reservoir contact area.

 

60 Day Production Gain Hypbrid_blue SSP

 

Marcellus bars

 

Propel SSP Technology Tail-In vs. Hybrid System

Utica Formation,
Liquids-Rich Gas Play

Increased contact area and conductivity

 Utica map

Just as with the previous hybrid design in the Marcellus formation, this case study documents the improved recovery possible when effectively transporting and uniformly distributing proppant in all dimensions throughout the fracture with a relatively low-viscosity fluid. The offset design included 24% crosslinked gel, which can be even tougher to manage post-breaking. The operator replaced formation-plugging viscosifiers with a Propel SSP technology tail-in. As this field trial reveals, the 71% Propel SSP technology tail-in eliminated the crosslinked and linear gels for a 12% production increase in the first 60 days.

 

60 Day Production Gain Hypbrid 71 SSP_blue ssp

 

Utica bars

 

Fracture Model Design Inputs: Effective Specific Gravity and Fluid Viscosity

Specific gravity and viscosity are necessary inputs for frac design and modeling. While specific gravity is readily provided by proppant suppliers, the effective specific gravity of a proppant with Propel SSP and the resulting fluid viscosity are dependent on the expansion ratio of the proppant in the base frac fluid. Expansion ratio is the comparison of the settled volume of a dry proppant substrate vs. hydrated Propel SSP. The electrical conductivity of the fluid is a key determinant for the expansion ratio and therefore, governs both effective specific gravity and viscosity.

A reduction in effective specific gravity of a proppant and fluid viscosity allow engineers to apply unconventional thinking toward future frac designs.

Effective Specific Gravity: A Function of Water Conductivity*

*Example of Propel SSP when applied to Northern White frac sand.

Determining Effective Specific Gravity

Use these steps to estimate the effective specific gravity of the proppant.

  1. Draw a horizontal line from the Water Conductivity axis to the Conductivity curve.
  2. Draw a vertical line from where the horizontal line intersects the Conductivity curve to the Effective Specific Gravity curve.
  3. Draw a horizontal line from where the vertical line intersects the Effective Specific Gravity curve to the Effective Specific Gravity axis to obtain the effective specific gravity reading.

Fluid Viscosity: A Function of Propel SSP Proppant Loading and Fluid Conductivity

Breaker Study with Ammonium Persulfate

Breaker testing has been performed with Propel SSP under various conditions, including temperatures, breaker loading rates, and time. Conventional viscosified fluids are deemed broken when the viscosity reduces to near that of water. To ensure complete system breaking with Propel SSP, both the fluid viscosity and settled bed volume were tested to ensure only the raw proppant substrate remains in the fractures.

Results confirm general trends that with increasing downhole temperature and breaker loading, break time decreases. Additionally, as loading of Propel SSP increases, additional break time is required.

Temperature is the Primary Factor for Breaking Propel SSP
Observed Trends in Breaking Time

Retains Substrate Integrity

Tests conducted at Stim-Lab, a division of Core Lab, and at Fairmount Santrol laboratories show that the hydrogel coating does not change the fundamental properties of the proppant substrate under downhole conditions. For these tests, 30/50 Northern White frac sand was used for both uncoated and coated substrate.

Sieve Analysis

Since the hydrogel coating is only 1 to 3 microns thick, there is no appreciable difference in sieve analysis in a comparison of raw 30/50 Northern White frac sand and the same substrate coated with Propel SSP.

Crush Resistance

Crush testing at 8,000 psi and 9,000 psi shows identical crush resistance for uncoated 30/50 Northern White frac sand and the same substrate using Propel SSP coating technology.

Wet Conductivity Testing

In modified wet conductivity testing at Stim-Lab, no appreciable difference was noted between uncoated and coated 30/50 Northern White frac sand. Results for the coated substrate are comparable to sand within normal test variance.

Efficient Proppant Transport

Detailed laboratory studies of Propel SSP have revealed efficient transport compared to sand in slickwater systems.

Tests have been conducted at Stim-Lab, a division of Core Lab, using a flow loop and fracture slot apparatus to visualize transport characteristics. Density of proppant in transport within the flow loop (measured via densometer) determines what percentage of the actual proppant loading rate is in transport through the fracture.

Flow rates in the apparatus typically range between 12-14 gpm. The dimensions of the slot are 0.31″ x 12″.

Key Results of Transport and Viscosity Tests
  • Propel SSP transports proppant like a cross-linked gel fluid system.
  • While viscosity does build with increased loading of Propel SSP, the frac fluid remains thin.
  • At low loading rates, Propel SSP provides significantly greater proppant transport at comparable viscosity to sand in slickwater.
Propel SSP Offers Efficient Proppant Transport in a Thin Fluid
Traction Carpet vs. Viscous Transport in a Thin Fluid

Slickwater: Traction Carpet
In slickwater, conventional frac sand forms a dune until the rising settled bed height restricts the flow area and increases fluid velocity above a critical level. Thereafter, most proppant transport is via traction carpet, in which a relatively thin layer of fluidized proppant is transported over the immobile settled bed. Proppant transport volumes are relatively low and require extended pumping times and larger volumes of water.

Propel SSP: Viscous Transport
Transport of Propel SSP is remarkably more efficient. In plain water, it can achieve viscous transport in fluid viscosities under 35 cPs at 3 pounds per gallon proppant loading. No supplemental viscosifiers are needed.

KEY BENEFITS

  • Low viscosity transport of high proppant concentrations
  • Even proppant distribution from well bore to fracture tip
  • Eliminates costly fluid sweeps after slickwater shutdowns
  • Superior technology improves fracture economics

KEY BENEFITS

  • Low viscosity transport of high proppant concentrations
  • Even proppant distribution from well bore to fracture tip
  • Maintains suspension of entire proppant concentration
  • Avoids dune formation to maximize proppant transport
  • Superior technology improves fracture economics

KEY BENEFITS

  • Maintains thin fluid suspension after shutdowns
  • Eliminates costly fluid sweeps after slickwater shutdowns
  • Superior technology improves fracture economics

KEY BENEFITS

  • Maintains suspension after shutdown to easily restart viscous transport
  • Eliminates costly fluid sweeps after slickwater shutdowns
  • Superior technology improves fracture economics

Reduce Cost per BOE with Efficient Self-Suspending Proppant Transport Technology

THIS PROPPANT BRIEF DISCUSSES:
  • Self-suspending proppant transport technology reduces cost per BOE by efficiently increasing the propped fracture surface area.
  • The technology’s suspension and stacking enable uniform proppant distribution throughout the low-viscosity, water-based frac fluid unlike proppant in slickwater and gel-based fluids.
  • The shear-stable, hydrogel polymer, which increases fracturing efficiency, breaks cleanly and flows back easily to significantly decrease formation and proppant pack damage.

Self-suspending proppant transport technology lowers cost per BOE by efficiently increasing the propped fracture surface area compared with traditional stimulation designs. By just adding to water, the shear-stable, hydrogel polymer rapidly swells, uniformly stacking proppant throughout the low-viscosity, water-based frac fluid unlike proppant in slickwater and gel-based fluids. The polymer breaks cleanly and flows back easily to considerably decrease formation and proppant pack damage. Operators working in heterogeneous formations are applying this efficient proppant and fluid system in one. Less water with fewer fluid additives in less time means achieving compelling hydrocarbon production success.

UNIFORM PROPPANT DISTRIBUTION

Petroleum engineers now have a better approach to stimulating oil and gas reservoirs. With self-suspending proppant transport technology, they can choose the optimal proppant for the application, relying on the technology to stack proppant uniformly in the fracturing fluid and travel farther in the formation. No longer do operators have to choose between finer-mesh, lower-conductivity proppant in favor of enhanced transport.

Stim-Lab slot test images

Additionally, in traditional completions designs, proppant falls out of the frac fluid and forms a dune. Operators often pump fluid sweeps to keep treating pressure down and populate the fracture. Self-suspending proppant has also eliminated this unnecessary process.

An engineered polymer—wrapped around a sand grain or ceramic proppant—rapidly swells in water, mobilizing placement of the proppant pack farther into the fracture. This eliminates the duning effect operators have encountered for decades.

The shear-stable polymer remains attached to the sand grain or ceramic proppant during blending and transport through the perforations and into the fracture network. Once in the fractures, the polymer-coated proppant relies on a conventional breaker. The breaker strips away the polymer, leaving only the original proppant in place, without traditional frac fluid’s negative effects that can lower formation permeability and proppant pack conductivity up to 60% and 70%, respectively. Self-suspending proppant has substantially diminished adverse of gel and slickwater based fluids that obstruct hydrocarbon production.

REDUCED COST PER BOE

A DJ Basin operator compared 11 wells on the same pad — six self-suspending proppant wells against five wells completed with a high viscosity friction reducer. Both used only 40/70 northern white sand. The self-suspending proppant wells averaged more than 20% cumulative production increase, without any further optimization of the completion design.

In another field trial, a Williston Basin operator also improved hydrocarbon production while significantly enhancing operational efficiency. The 11-well trial included 6 self-suspending proppant wells and 5 wells completed with frac sand in a 30-lb crosslinked gel-based fluid. The new technology wells required 77% fewer fluid additives and 14% less pumping time. On average, the operator increased production 39% while paying for the proppant investment in less than 4 months.

CONCLUSION

A better completions design is supporting operators in their search for lower-cost production. Self-suspending proppant transport technology, whose robust hydrogel polymer has opened a new chapter in oil and gas reservoir stimulation, is increasing hydraulic fracturing efficiency and reducing cost per BOE.

Reduce Formation and Proppant Pack Damage with Self-Suspending Proppant Transport Technology

THIS PROPPANT BRIEF DISCUSSES:
  • A shear-stable, hydrogel polymer ensures uniform proppant distribution in frac fluid.
  • The polymer breaks cleanly and flows back easily to reduce downhole damage.
  • This cleaner downhole condition increases formation retained permeability and proppant pack regain conductivity.

The shear-stable, hydrogel polymer—wrapped around a standard-mesh sand grain or ceramic proppant—is the engineered wisdom of self-suspending proppant transport technology (Figure 1). By just adding to water, the polymer rapidly swells around each proppant grain, for effective suspension and transport in low-viscosity fluid; unlike proppant in slickwater and gel-based fluids. Additional chemicals are unnecessary to facilitate proppant transport.

This stacking effect hinders settling and eliminates duning as with traditional fluids.

A completely stacked fluid column allows proppant to travel farther and remain higher in the fracture for an increased propped fracture surface area. Once in the fractures, the polymer breaks cleanly and flows back easily with substantially reduced downhole damage.

This cleaner, residue free system, increases formation retained permeability and proppant pack regain conductivity, allowing operators to increase hydrocarbon production at lower cost per BOE.

Magnified self-suspending proppant image
ROBUST HYDROGEL POLYMER

The robust hydrogel resists swelling in humidity while tolerating high shear forces during fracing; it remains attached to the proppant grain until chemically broken. The technology is unaffected by cold water unlike gel-based frac fluids that require temperature as high as 80° F and a prehydration unit to reach the desired viscosity. This technology can help operators mitigate up to $500,000 per well to heat water in the winter.

The shear stable hydrogel also functions as a fluid leakoff control agent, further enabling completion design flexibility. The robust, versatile technology allows operators to select the ideal proppant, fluid volume, pump rate and proppant concentration without sacrifice to well performance in favor of operating efficiency.

A CLEAN BREAK PROTECTS WELL INTEGRITY

Fairmount Santrol R&D verified complete polymer breaking with ammonium persulfate and magnesium peroxide, among others, by testing the fluid viscosity and settled bed volume. After breaking the polymer and upon fluid flowback, fluid additive residue was eliminated. This is the ideal condition after fluid flowback unlike what happens all too often with traditional guar-gel residue remaining downhole.

TECHNOLOGY RETAINS FORMATION PERMEABILITY AND FRACTURE CONDUCTIVITY

Stim-Lab confirmed self-suspending proppant technology maintains downhole integrity without damage to the formation and proppant pack that limits hydrocarbon flow. As far as the formation, a Stim-Lab test showed 100% retained permeability for self-suspending proppant while the conventional fluids could not match this result. Retained permeability for slickwater, linear gel, and crosslinked gel decreased 13%, 6%, and 14%, respectively.

Concerning the proppant pack, another Stim-Lab test recorded complete regain conductivity for self-suspending proppant and slickwater, but the guar-based fluids regain conductivity was 50% to 60%. Well damage is reduced with self-suspending proppant; the result of residue free polymer remaining attached to the proppant during frac treatments.

REDUCED COST PER BOE

There are better results in field trials also. A Niobara formation operator compared three self-suspending proppant wells against three other wells completed with a high viscosity friction reducer based fluid system, both using only 40/70 northern white sand. The self-suspending proppant wells improved production more than 20% in the first 10 months.

In the Escondido formation, self-suspending proppant as a 46% tail-in boosted 60-day initial production in 1 well by more than 55%. A higher proppant concentration enabled significantly better effective fracture half-lengths. The operator improved fracturing efficiency by decreasing pumping time 25%, fluid additives 15%, and water consumption 10%. The operator completed the offset well with 20/40, 40/70, and 100-mesh Northern White sand in slickwater.

CONCLUSION

Self-suspending proppant transport technology is a new method for completing wells. The shear-stable, hydrogel polymer’s clean break and flowback are laboratory tested and field-proven. Operators are now reducing cost per BOE with greater efficiency while considerably reducing the formation and proppant pack damage caused by slickwater and gel-based fluids.