Control of formation material and debris crushed by proppant intrusion into the formation face, as well as proppant flowback, are all-too-familiar issues that must be addressed during completion procedures to help optimize the economic recovery of reserves from oil and gas reservoirs. Recent studies have shown these two factors to be the primary causes of rapid production decline.

Forestalling proppant pack plugging in both low and high perm reservoirs and the loss of proppant in low perm reservoirs can significantly improve the connection, or conductivity, between the producing formation and the wellbore, enhancing the likelihood that a well will achieve economic production rates. Higher initial production rates help recover more reserves faster, improving the net present value of oil and gas development projects; sustaining production at high rates for as long as possible can help extend the productive life of a given well and help maximize ultimate recovery.

Most treatments incorporating fracture stimulation reliably increase initial rates of recovery; however, experience shows that maintaining production at desired rates for months or years after a well begins producing is not a given.

Obstacles to conductivity
To begin with, the process and procedures used in drilling and completing a high-permeability reservoir often cause damage to the inflow capability of the reservoir. As with many procedures, inducing a controlled fracture into the formation can damage the reservoir being stimulated. Plus, the gravel pack or proppant pack placed in the well to optimize conductivity as part of the completion process usually begins to lose part of its effectiveness soon after production begins.

Intrusion of formation material into the pack contributes to decreased production in virtually all formations, even "clean" sands. Formation material entering the pack and plugging pore spaces continually decreases the flow area and increases flow path tortuosity (Figure 1). Some multi-rate buildup tests indicate these effects account for as much as 80 percent of total skin.
In addition, stress cycling—as a result of variable flow rates or temporary shut-in, for example—can contribute to reduced effective fracture width by causing the pack to shift and allowing formation material to intrude.

In addition, stress cycling—as a result of variable flow rates or temporary shut-in, for example—can contribute to reduced effective fracture width by causing the pack to shift and allowing formation material to intrude.

Slowing down production rates can inhibit migration of material from the formation interface as well as resultant plugging of the gravel pack or proppant pack conductivity. However, the economic conundrum created by high drilling, completion, and production costs and declining reservoir quality forces producers to place a high premium upon producing wells at maximum rates to generate adequate revenues.

As a result, when production rates inevitably begin to decline, producers typically respond by increasing choke size and accelerating pumping rates or by adding compression horsepower. Ironically, as they pull harder on the reservoir to maintain production, producers at the same time increase the potential for instability in the pack and pack-formation interface.

SMA enhances conductivity
Halliburton, in the late 1990s, introduced a surface-modification agent (SMA), called SandWedge® enhancer, that significantly improves conductivity resulting from hydraulic stimulation treatments using water-base fluids such as SeaQuest® service for offshore FracPac^SM treatments and SilverStim® and SilverStim LT services for hard rock frac stimulation. Applied directly onto dry proppant or gravel at the well site before it is added to the fracturing fluid, SandWedge enhancer chemically alters proppant surfaces to dramatically increase the intergranular surface friction of individual proppant grains. Proppant grains coated with the SMA achieve better proppant pack porosity and permeability at reservoir closure pressures as great as 4,000 psi.

In addition, proppant grains coated with SandWedge stick together better in the pack and exhibit little or no movement in response to high flow rates and extreme cyclic loading. This improves the stability of both the proppant pack and the pack-formation interface, preventing formation material from entering the proppant bed and better sustaining effective fracture width and fracture conductivity in high-stress reservoirs (Figure 2).

Conductivity endurance technology
Recently completed studies of production profiles of wells treated with SandWedge agent—as well as the results of recent third-party laboratory tests—have confirmed that invasion of formation materials into the proppant pack and loss of effective fracture width are the two leading causes of production declines following propped stimulation treatments.

Conversely, the same findings show that SandWedge enhancer can help eliminate or significantly reduce such counterproductive forces when applied as part of a comprehensive conductivity endurance program based upon thorough reservoir understanding and incorporating optimally sized proppant grains and suitable proppant materials (Figure 3).

When used in this manner, the proprietary SMA can enable higher production rates for longer time periods with minimal interruptions in wells in which the reservoir is prone to releasing fines material, or in which a fines-laden proppant is used in the treatment (Figure 4). SandWedge also is prescribed for applications in which the rate of production must be maintained but with less pressure drop, or when a more aggressive production program is required but damage must be minimized.

Larger proppant can boost conductivity
Saucier's Rule—which has guided industry practice—instructs that to produce oil or gas from a sand-prone well with unsteady flow without the risk of plugging the proppant pack, it is necessary to select proppant grains no more than 5 or 6 times the size of the average grain size of the reservoir being produced. Saucier also holds that a pack-grain-to-formation-grain size ratio of 10-to-12 can allow formation grains to become lodged in pores in the pack, and a ratio of 15 or more can allow formation sand to flow through the pack into the wellbore.

However, Halliburton has learned that if proppant gains are coated with SandWedge enhancer, they can be 16 to 20 times the average reservoir grain size and still produce oil and gas at unsteady flow rates without plugging the pack or producing sand. In essence, that means fracture-stimulation treatments incorporating SandWedge enhancer and larger proppant in formations prone to sand production can help achieve many times the conductivity of a treatment of the same design but utilizing a conventional resin-coated proppant.

This can result in higher initial production rates. And, because SandWedge agent remains active long after a well is completed, the higher production rates may be sustained for much longer times than was initially believed when SandWedge enhancer was introduced.

Noteworthy production added offshore
In one example, researchers compared the production of four virtually identical offsetting wells in the Gulf of Mexico (GoM), two of which had been completed using conventional stimulation and sand-control technology and two of which had been completed using SandWedge conductivity endurance technology (Figure 5). In the 12 months following initiation of production, the output of the two conventionally completed wells declined rapidly. Meanwhile, the wells treated with SandWedge agent showed essentially no production declines, achieved cumulative production about three times that of the conventionally completed wells, and generated more than $330,000 extra production per vertical foot of pay than their counterparts in only the first year.

In another similar production comparison of four GoM wells, the well in the group treated with SandWedge produced more initially than its conventionally completed counterparts, maintained higher production, and achieved 50 percent more cumulative recovery in the first year. As a result, the SandWedge-agent well generated more than $52,000 extra production per foot of pay during the study period than the other wells.

Expanding SandWedge applications
SandWedge agent is equally effective enhancing conductivity in low-permeability formations, by providing a stabilized proppant pack and inhibiting invasion of formation material crushed by closure stress at the proppant interface. This stress-induced source of formation fines material can lead to plugging of the proppant pores (conductivity) with resulting loss of effective fracture width.

For completions in formations where high rates of proppant flowback or high bottomhole static temperatures (BHSTs) during initial cleanup are major concerns, Halliburton has introduced SandWedge® XS agent, a specially formulated resin that is added in the final step of a conventional SandWedge enhancer treatment.

Proppants treated with SandWedge XS agent become more tacky and more resistant during cleanup to flow velocities greater than 5 barrels per day per perforation or BHSTs greater than 250° F.

SandWedge XS agent is a conductivity enhancer, and is not a proppant flowback additive. It will not stop proppant flowback under harsh conditions, such as high flowback rates or high temperatures. In harsh conditions, Halliburton's new Expedite® system can help control proppant flowback and enhances conductivity.

Controlling proppant flowback
Expedite® service also is called for in situations where controlling proppant flowback following fracturing is a primary consideration.

Expedite service uses the company's direct-coating process to apply a proprietary resin mixture to proppant to achieve three times as much conductivity as conventional resin-coated proppants at 4,000 psi and up to 40 percent better conductivity at 10,000 psi.

The proprietary resin mixture provides a step-change performance improvement over conventional proppant flowback control systems, enabling earlier production and promoting cleanup of frac fluids (Figure 6). At the same time, Expedite can help eliminate the potential of fibrous materials plugging surface equipment or conductivity deterioration that can occur if the coating of precoated proppant is damaged during storage and handling.

The development of compressive strength in the consolidated proppant pack is crucial to effectively controlling proppant flowback. Yet, widely used resin-coated proppants frequently cannot provide the compressive strength needed soon enough (if at all), because closure stress is required to provide good grain-to-grain contact prior to resin curing.

Some formations may not allow the fracture to close enough during the first 24 hours after a stimulation treatment to prevent proppant flowback. In fact, many reservoir rocks do not close sufficiently to prevent proppant flowback during the first 90 days after fracturing. Conventional curable resin coatings may harden prior to the application of closure stress sufficient to allow bonding between proppant grains.

Proppant packs formed using Expedite provide compressive strength quickly and can provide more than sufficient compressive strength to reduce or stop proppant flowback under the most severe conditions, even with minimal closure stress (Figure 7). In addition, proppant packs treated using Expedite service can provide and maintain exceptionally high conductivity.

Extreme conditions in South Texas
A producer in South Texas needed to stimulate a series of wells where typical downhole conditions included bottomhole temperatures greater than 325° F and closure stresses up to 12,000 psi. Typical stimulation treatments were pumped at 35 barrels per minute to place 300,000 pounds of bauxite at 2 to 8 pounds per gallon.

Despite such extreme temperatures and pressures, Expedite agent enabled cleanup of the wells to begin after only 2 hours and reduced proppant flowback by 60 percent, compared with conventional resin-coated proppants used previously in the area. More importantly, Expedite helped increase average production rates by 30 percent, and achieved natural gas production of 40 million cubic feet per day in 65 hours, a 68-percent improvement over results achieved with conventional proppants.

Because of the wide demand for Expedite service for a variety of reservoirs, Halliburton has designed proprietary resin formulations to help improve the results of fracture treatments in virtually any formation. These formulations include Expedite™ XC agent for reservoirs with BHSTs of 60 to 225° F; Expedite™ XP agent for BHSTs of 200 to 375° F; and Expedite™ XT agent for BHSTs of 300 to 550° F.