Summer 2009
New Proppant for Horizontal
Well Frac Treatments

Hexion recently developed and field tested a new line of proppants specifically designed for horizontal wells. These unique, curable resin coated proppants are available in a -16+40 mesh size. XRT Gold H™ was designed specifically for applications with closure stresses ranging from 6,000 to 10,000 psi (41 – 69 MPa) and bottom-hole static temperatures up to 450°F (232°C). Use of the patented XRT™ (eXtreme Resin Technology) system to encase specially graded frac sand has yielded a proppant with very low crush and high flow capacity.

XRT Gold H offers increased bond strength and high fracture flow capacity for horizontal wells. Its grain-to-grain bonding is well suited for these well types where fluid loading and surging as well as production rate changes from facility shut-ins are common. These proppants prevent flowback, are resistant to cyclic stress changes, reduce proppant embedment, and are also a good fit where wellbore clean-out is a concern. XRT Gold H proppants provide strong bonding in the fracture with closure while wellbore consolidation is eliminated, facilitating ease of removal. They retain over 90% original bond strength after prolonged slurry times at elevated temperatures. The XRT resin also minimizes breaker interference common with curable resins. These unique proppants have been successfully field tested and have proven to provide superior results for horizontal wells.

Fracture Flow Capacity
XRT Gold H provides superior fracture flow capacity, which is essentially the fracture’s ability to conduct oil and gas. Besides the well known factors such as proppant size, strength and density, fracture flow capacity is also affected by several crucial factors:

  • Proppant Fines
  • Effective vs. Reference Conductivity
  • Cyclic Stress
  • Proppant Pack Rearrangement
    and Flowback
  • Proppant Embedment
  • Downhole Proppant Scaling

Proppant Fines
Proppant fines generation is one of the major contributors to poor fracture treatment results. As the fractured well is produced, closure stress increases on the proppant grains. Conventional proppants begin to fail quickly in wet, hot downhole environments. These broken grains produce fines which migrate and decrease pack permeability.

It has been determined that just 5% proppant fines decrease fracture flow capacity by as much as 60%, significantly reducing well productivity.*

More Realistic Testing Procedures Developed
The API RP-56 proppant crush test procedure was developed in 1983 to test uncoated fracturing sands. This test is run dry and at ambient temperature. It was not designed to test curable resin coated proppants which require both temperature and stress to bond in the fracture.

To more accurately simulate downhole conditions, Hexion™ developed test procedures called the Wet, Hot Crush Test and Cyclic Stress Test. These tests demonstrate how different proppants perform more realistic downhole conditions versus the RP-56 test which is performed in a dry, room temperature environment. These modified versions of the API RP-56 test are conducted under simulated wet, hostile reservoir environments at elevated temperature and pressure. These new tests can also evaluate both curable and precured resin coated proppants.

Wet, Hot Crush Test
Downhole conditions in typical fractures subject proppants to elevated temperatures in a wet environment. In an effort to more closely simulate these conditions, Hexion developed the Wet, Hot Crush Test. This newer test is an updated version of API RP-56. Unlike the basic API test, the Wet, Hot Crush Test first exposes the proppant to 2% KCl fluid at 200°F (93°C) for 24 hours under 1,000 psi (7 MPa) closure stress prior to testing. During crushing, the sample is also continuously held at a constant 200°F (93°C) and the sample is exposed to 2% KCl fluid. After crushing at temperature, the amount of fines generated are measured once the tested material has been dried in a convectional oven.

By exposing the proppant to this simulated downhole environment prior to testing, the results obtained from the crush test provide a more realistic representation of downhole proppant pack conditions. The graph on the right shows the percentages of fines generated by XRT Gold H, lightweight ceramics, and uncoated frac sand at 6,000 and 8,000 psi (41, 55 MPa) closure stress. The uncoated proppants generated a much larger amount of fines when compared to XRT Gold H since it is a curable resin coated proppant.

Fines Generation Reduction
Different proppants have been developed over the years to address the issue of fines generation and migration. Curable resin coated proppants have proven to be the most successful.

Due to their ability to bond, curable resin coated proppants provide a greater reduction in fines generation since the surface area of the grain-to-grain contact is increased. Instead of just single grain point loading, there are multiple grains bonded together in a network of deformable surfaces. This unified proppant pack redistributes the stress on the proppants within the fracture, decreasing the stress on each individual grain.

Curable resin coated proppants also reduce the amount of loose fines that are able to break off and migrate through the proppant pack. When grain failure occurs with an uncoated proppant or even a precured resin coated proppant, loose fines are generated. These fines become mobile and reduce pack permeability. With a curable resin coating, even if the grain breaks, the coating will encapsulate the fines, limiting migration.

Effective vs. Reference Conductivity
Traditionally, proppant performance has been measured using reference (or baseline) conductivity testing. Proppant conductivity charts are published using the reference data, but unfortunately, like the API crush tests previously mentioned, they do not accurately reflect downhole conditions.

A typical baseline conductivity test is run at a flowrate of only .0051 cubic feet per day (CFD) which is just 6 milliliters per hour, therefore fines do not migrate. Post frac treatment flowrates are 1 to 10 million CFD or more, a real-world flowrate a billion times greater than the baseline test. This high flow rate causes migration of fines and a decrease in fracture conductivity.

Effective conductivity is a more accurate measurement of downhole proppant performance. It is calculated using the Coulter & Wells Method which measures the effect of fines on conductivity. The graph on the right shows that a small amount of fines causes a large reduction in proppant pack conductivity. As previously discussed, only 5% fines leads to a 60% decrease in fracture conductivity.*

The expected downhole performance of a proppant changes dramatically once effective conductivity is taken into consideration. The corresponding chart compares the effective conductivity of XRT Gold H to an uncoated lightweight ceramic. The light blue line represents the published baseline conductivity for the lightweight ceramic. The dark blue line represents the calculated effective conductivity which is significantly lower. The effective conductivity of the curable resin coated proppant in orange is only slightly different due to its resin coating which greatly mitigated fines. As the chart indicates, while the reference (baseline) conductivity is higher, the effective conductivity is actually lower when real-world downhole conditions are factored into the results.

This chart compares the effective conductivity of XRT Gold H to uncoated frac sand. As shown in the chart in yellow, uncoated frac sand baseline conductivity levels decline steadily under increasing closure stress. However, the effective conductivity reveals how rapidly the curve declines even at lower stress levels. Conductivity levels are extremely poor even at 6,000 psi (41 MPa), resulting in drastically reduced oil and gas production. XRT Gold H once again retains its conductivity, changing only slightly as closure stress levels increase.

Cyclic Stress
Proppant pack cyclic stress resistance is another important factor when designing fracturing treatments. Throughout the life of the well, a proppant pack is subjected to numerous stress cycles caused by well interventions and shut-ins. These changes in stress can cause the proppant pack to shift, fatigue, and generate fines – leading to decreased conductivity.

Under normal circumstances, these forces will break conventional proppant packs – reducing pack integrity and conductivity. However, curable resin coated proppants remain flexible due to the outer resin coating’s ability to conform to the changing forces. Due to this ability, resin coated proppant packs are less likely to break under cyclic stress. The curable resin coating also helps minimize fines.

Cyclic Stress Test
The Cyclic Stress Test was developed to more accurately reflect downhole conditions on proppants caused by closure stress changes. This test is similar to the Wet, Hot Crush Test, but was designed with three cycles to simulate real-world conditions caused by changes in closure stress.

Prior to testing, the sample is exposed to 2% KCl fluid at 200°F (93°C) for 24 hours under 1,000 psi (7 MPa) closure stress. The test is then run from 3,000 to 8,000 psi (21 – 55 MPa) for a total of three cycles. The temperature is held at 200°F (93°C) and the sample is exposed to 2% KCl solution during these cycles. After crushing at temperature, the fines generated are dried in a convectional oven and measured.

These pictures compare the Cyclic Stress Test results of XRT Gold H to a lightweight ceramic and raw sand. The photos show that the lightweight ceramic and raw sand generated a very high number of fines – greatly decreasing fracture conductivity. XRT Gold H showed much less fines generation. As previously discussed, the fines generated greatly effects conductivity. Reference conductivity does not take these fines into account, effective conductivity gives a more accurate view of downhole proppant performance.

Proppant Pack Rearrangement
and Flowback
High production rates significantly increase velocity in the proppant pack. Proppant grains in the fracture without a resin coating have the ability to shift and move. In the fracture this movement can cause an uncoated proppant pack to rearrange. Near the wellbore, this reallocation leads to proppant flowback.

This flowed back proppant can not only damage surface facilities and production equipment, but it also leads to unnecessary workovers and clean-outs which are costly and time consuming. In horizontal wells, proppant flowback can be extremely troublesome as it can deposit in the wellbore along the horizontal lateral. Ceramics, due to their abrasive nature are particularly damaging, sometimes causing catastrophic well failure.

Post treatment proppant flowback is a leading cause of well production decline. It can cause lost production from flow rate curtailment or sometimes even complete well shut-in. Proppant flowback also leads to lower near-wellbore fracture flow capacity. In the fracture away from the wellbore, proppant pack rearrangement can cause significant reduction in fracture width leading to a loss of fracture flow capacity.

Due to their ability to bond, curable resin coated proppants provide flowback control by forming a lattice network of multiple linked grains. This consolidated proppant pack inhibits individual grains from breaking loose and flowing back into the wellbore. This proppant pack also maintains its integrity even after multiple shut-ins over the lifetime of the well. It also allows for more aggressive well flowback with less concern about fines.

XRT Gold H addresses proppant flowback control with a unique stress-to-bond coating that forms under a combination of closure stress and temperature in the fracture. In the event that proppant is left in the wellbore, this stress-to-bond technology can easily be flowed back or circulated out if left in the wellbore.

Proppant Embedment
Hard, brittle proppants such as lightweight ceramics can embed into softer fracture faces. Fracture conductivity is lowered due to fracture width reduction. As an example, ceramic proppants can embed into the fracture face up to 75%, leading to a 17% loss in flow capacity**. Curable resin coated proppants such as XRT Gold H minimize embedment since they are bonded together in a proppant pack.

Proppant Scaling
Downhole proppant scaling is a geochemical reaction which results in the loss of pack porosity and permeability. Scaling essentially creates fines in the proppant pack that reduce fracture flow capacity. This is generally seen in uncoated proppants. Uncoated lightweight ceramics can lose up to 90% pack permeability in only a few days. High density uncoated ceramics such as bauxite can lose 50% to 60% of their permeability. Resin coating greatly reduces the impacts of scaling. Field studies clearly demonstrate that wells fractured with resin coated proppants have significantly higher long-term productivity***.

Successful Field Applications
XRT Gold H has already been utilized in numerous wells throughout the United States. As horizontal well activity increases, XRT Gold H is rapidly becoming the proppant of choice for operators due to its field proven success in higher temperature and pressure applications.


*Coulter & Wells, Journal of Petroleum Technology, 1972.
**Courtesy of SPE 16900 (An Evaluation of the Effects of Environmental Conditions and Fracturing Fluids Upon the Long-Term Conductivity of Proppants, G. Penny, Stim-Lab, Inc., 1987 ).
***Courtesy of SPE 118175 (Prevention of Geochemical Scaling in Hydraulically Created Fractures – Laboratory and Field Studies, P. Nguyen, J. Weaver, R. Rickman, Halliburton, 2008).


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