Drilling and Completion Technology

Low-density propping agents improve hydraulic fracturing in the Permian basin

A new proppant created from ground particles filled/ coated with resin remains nearly buoyant in water-based frac fluids to more efficiently pack created fractures for greater, sustained fluid inflow.

Randall Edgeman, BJ Services Co., Midland, Texas

This article summarizes the development of low-density propping agents for primary applications in water fracs. The use of these new proppants in improving transport and more complete packing of created fractures is discussed. And illustrations show comparative fracture cross-sections, packed with conventional proppants, that only create a proppant bank around the wellbore, with one packed to a high-percentage of the fracture's total length and height using lighter-weight proppants. To date, more than 130 frac treatments have been performed in the West Texas Permian basin using this patented new technology, basically using a manufactured, low-density material called LiteProp.

INTRODUCTION

Hydraulic fracturing has experienced an amazing array of innovations and technical advancements since its inception in the late 1940s. The oil and gas industry continues to rely on fracturing to develop resources in mature basins and other areas with marginal production economics. The Permian basin in West Texas exemplifies both criteria and, therefore, has had a long, successful history with respect to fracture stimulation.

In its purest form, hydraulic fracturing offers a means to part a formation with fluid pressure and create highly conductive flow paths extending laterally from the wellbore to increase production. Typically, a propping agent, or proppant, is placed in the fracture to ensure that the flow path remains open after hydraulic treating pressure is released.

Technical advancements over the past two decades primarily focused on development of increasingly cleaner and more efficient fracturing fluids, typically cross-linked (gelled) polymer systems. Proppant technology, on the other hand, has not benefited from the same degree of research and innovation (with the possible exceptions of resin-coating and ceramic particle technologies). This is because the physical dimensions of any particular fracture constrain the finite amount of proppant that can be physically placed.

This puts an upper limit on the conductivity of the final proppant pack. Historically, the industry has sought “ideal” fracturing fluids that maximize proppant transport, yet minimize the damage imparted to the formation and final proppant pack conductivity. These two design criteria are by nature diametrically opposed; hence, the ongoing R&D challenge.

PROS AND CONS OF WATER FRACS

We have long recognized that un-gelled water is one of the cleanest and most economic fluids for fracturing. Where formation compatibility issues and fluid leak-off are minimal, there has been substantial interest in using un-viscosified water as a primary frac fluid. These treatments are commonly referred to as water fracs, slick-water fracs, or (occasionally) dendritic fracs. This type of frac job typically involves pumping very large amounts of water, with friction reducer and relatively small volumes of proppant, at very high rates. Where applicable, such treatments produce adequate results at a reduced total cost, compared to those using traditional gelled fluids – making water fracs more economically viable than fracing with gelled fluid systems.

Like all stimulation techniques, water fracs have their advantages and disadvantages. The key with this particular technique is candidate selection, i.e., applying it to areas or formations suited to its unique advantages. Potential water frac advantages include:

• It is operationally and chemically straightforward.
• Very long hydraulic frac lengths can be generated.
• IP rates can be comparable to conventional treatments.
• Costs are less than conventional treatments.

As might be expected, water fracs also have several disadvantages, for example:

• Limited to low sand concentrations
• Rapid screen-out potential
• Short effective frac lengths
• Resulting production declines are steeper than similarly sized conventional jobs
• Water zones below are particularly risky.

Virtually all of the disadvantages associated with water fracturing are symptoms of poor proppant transport. So if proppant could be placed effectively by water, the potential negative consequences would be greatly diminished, or eliminated entirely.

In its simplest terms, a fluid's ability to carry or transport a particle is proportional to the settling velocity of the particle relative to the surrounding fluid. Since the fluid in question is water (Newtonian), the terminal settling velocity (Vt) of any particle (proppant) can be estimated using Stokes' law:

    V_t = (r_p – r_f ) g_cd_p² /18m_f

Since water fracing has been proven to be a popular and cost-effective method to stimulate many marginal reservoirs, given that its major drawback is poor proppant transport, it was logical to ask: “Is there a way to improve the proppant transport characteristics of water?” For an answer, Stokes' law was examined on a variable-by-variable basis to find a way to decrease the terminal settling velocity of proppant in the carrier fluid (in this case, water).

IMPROVING WATER-FRAC PROPPANT TRANSPORT

The most common method to reduce settling velocities is decreasing the diameter (d_p ) of the proppant. This approach is particularly effective since the diameter term is squared in Stokes' law; thus, if the diameter is cut in half, the settling velocity is cut by a factor of four. However, this technique has its limits, since proppant conductivity is also proportional to diameter, with an exponent that is (unfortunately) greater than two. This means the settling benefit gained by reducing diameter is rapidly offset by the resulting reduction in fracture conductivity.

Similarly, other variables in Stokes' law were examined. It stands to reason that viscosity (m_f) of the fluid could be increased to reduce the proppant's terminal velocity. But gelling the fluid negates the benefits of water fracing. Altering the frac fluid density (r_f) was deemed impractical because, to achieve parity with proppant (sand) density, one would need to find an economic source of 22.1-ppg non-damaging fluid – not very likely!

This process of elimination determined that the most practical way to improve proppant transport in water would be to decrease proppant density until it approached carrier fluid density. Obviously, since the fluid in question is water, that requires a prospective proppant to have a specific gravity as close as possible to one. The prospective material would also need to provide adequate conductivity across as wide a range of closure stress and temperature as possible.

FINDING EFFECTIVE, LOW-DENSITY PROPPANTS

Many different compounds were investigated in the search for a material that exhibited low specific gravity and a useful conductivity range. Extensive lab screening against the previously mentioned design constraints led to selection of a cellulosic substrate, impregnated with and encapsulated in, a pre-cured resin coating. The organic nature of the substrate provided substantial porosity that could be filled with low-density resin to achieve both strength and a low specific gravity. The entire particle was coated with an external film and cured both to protect the substrate from degradation and to add additional closure resistance, Fig. 1.

Fig. 1. Low-density proppant preparation.

The result of this process is a proppant with roughly the same conductivity characteristics of Ottawa (Jordan) sand, yet has an average specific gravity of 1.25 g/cc. Sand has a specific gravity of 2.65 g/cc, and premium man-made proppants can have specific gravity as high as 3.55 g/cc. This density difference means the new low-density proppant particle will settle at a rate up to 6.6 times slower than a similarly sized sand particle in fresh water. This decrease in terminal settling velocity will translate into significantly longer proppant transport distances. Additionally, when the low-density particles are placed in a saturated 10-ppg brine (sg = 1.2), the resulting settling rate is so low that the particles are almost neutrally buoyant.

The photo in Fig. 2 illustrates the dramatic difference in settling rates exhibited by two conventional fracturing proppants, vs. two ultra-lightweight proppants in an otherwise static 9.5-ppg brine solution. The 20/40-mesh proppant materials, left to right, are: bauxite, Ottawa sand, LiteProp 175 and LiteProp 125. The brine-filled tubes were inverted just two seconds before this photograph was taken, in a controlled environment.

Fig. 2. Different settling rates in 9.5-ppg brine solution of two conventional proppants, bauxite (1), Ottawa sand (2), and two patented ultra light-weight proppants, LiteProp 175 (3) and LiteProp 125 (4).

MODELING LOW-DENSITY PROPPANT PERFORMANCE

In terms of propped length, the decreased settling rate exhibited by the low-density proppant yields significantly longer fractures than previously possible with conventional sand in a water frac. Fig. 3 represents a typical post-frac proppant distribution, in which the sand created a proppant bank or dune adjacent to the wellbore. Conductivity of this sand pack is usually very high due to high areal concentrations associated with this type of proppant distribution.

Fig. 3. Conventional water-frac, post-frac proppant distribution profile.

However, the figure also illustrates that the entire pay interval was not propped and the effective propped length is not optimal, given the created hydraulic fracture length. This type of fracture treatment on a low-permeability zone would result in a production stream that declined rather quickly and did not drain the entire net payzone thickness.

To improve the performance of the completion represented in Fig. 3, it was decided to take advantage of the almost non-existent settling rate of the low-density proppant in a 10-ppg brine carrier fluid. Fig. 4 represents the resulting fracture profile of the same example used in the conventional water frac scenario. However, with this simulated treatment – in which pumped fluid volumes are identical to the previous example – the mass of low-density proppant placed was just 1/5 that of the sand example. Additionally, this smaller proppant mass was pumped in filtered 10-ppg brine.

Fig. 4. Fracture profile with low-density proppant in 10-ppg brine carrier fluid.

The low-density particles are carried without the excessive settling associated with typical water fracs. This scenario also results in a completion in which the entire pay thickness is propped open, creating an effective propped length about four times greater than the sand example. The resulting conductivity is lower than with sand, but given the low permeability of the candidate wells, the created fracture length dominates completion results.

PROVING EFFECTIVE IN RE-FRACS AND WATERFLOODS

This type of treatment is proving particularly effective in re-stimulating older wells with low permeability, and in stimulating marginal pay that had been bypassed due to poor economics. Typically, the post-frac fluid entry rates from these low-density propped fracs can be as high as seven fold over pre-frac conditions. These results have even been observed in wells previously fractured with conventional proppants.

The new low-density proppants have also been used to treat under-performing wells in mature waterfloods that have been previously stimulated. Frequently, these particular wells flowed for a significant amount of time after the frac, even though they were in a “pumped-off” condition prior to re-stimulation. Measured pressures suggest that either: 1) the frac exceeded the original drainage radius, or 2) it contacted pressure support from an offset injector. Although it has not yet been determined, which is the case, both scenarios would require significantly longer effective frac length than had been previously achieved.

PURSUING DATA TO EVALUATE FULL POTENTIAL

To date, more than 130 fracture treatments have been performed in the Permian basin using this patented, new low-density, ultra-lightweight proppant. The innovative nature of this low-density proppant material means the well design optimization process is ongoing. Many different techniques to place the material have been proposed and tried in the field.

These techniques are primarily focused on taking advantage of the low settling rates these proppants exhibit. However, other benefits include the ability to maximize effective fracture length by increasing the propped area within the fracture. Additionally, the low-viscosity carrier fluids that can be used with low-density proppants will create greater fracture length, vs. height, and improve areal coverage.

Proppant monolayers. Ongoing efforts with several Permian basin operators will create a critical mass of treatment data that will yield better evidence of these products' full potential. A major area of interest is the investigation into creating partial proppant monolayers. This phenomenon was well documented in the fracturing research literature in the 1960s.

The concept behind creating a partial monolayer is to place proppant into a fracture width equal to one particle diameter. Researchers historically tried to determine the optimal proppant concentration, just below what a full monolayer would require, to maximize resulting conductivity while using a minimum amount of proppant. This concept derived from lab conditions proved difficult, if not impossible, to replicate in the field due to the technological limitations of the day.

Analysis of recent post-frac results combined with an examination of estimated areal proppant concentration suggests that a proppant monolayer is probably being created with low-density proppants.

Reasons for monolayer success. It is believed that, this time, creation of partial monolayers might be successful for these reasons: 1) Gelled fluids are used to transport proppant laterally. With low-density proppants, fluid viscosity is not needed; 2) When non-viscosified fluids are used (in water or slick-water fracs), conventional proppants settle quickly and final distribution varies too much to create a monolayer. This does not apply to the new low-density proppants; and 3) Proppant embedment in the fracture face becomes significant at very low proppant concentrations. The highest success rates achieved with these new low-density proppants have been in very high modulus dolomites.

SUMMARY

Low-density proppants have opened new opportunities for hydraulically fracturing wells in the Permian basin. The low specific gravity of these materials allows fracturing treatments with non-damaging fluids to place propping agents at greater distances from the wellbore than has been possible with gelled systems. This greater propped (or effective) frac length manifests itself in well performance superior to conventionally treated offset wells. 

THE AUTHOR
	Randall Edgeman, region engineer for BJ Services Co., Midland, Texas, graduated from the University of Oklahoma in 1987 with a BS in petroleum engineering. He has 17 years of combined industry experience with various service companies and operators.