Extraordinary production improvements have made ultralightweight proppants a standard component of fracture stimulation treatments in many areas of the San Juan and Permian basins and the Barnett Shale, among others.
With specific gravity very close to that of slickwater, these proppants enable propped fracs with much greater effective fracture lengths and higher conductivity compared with natural sand, and with much lower total volumes of proppant.
Broader use of these efficient proppants has been limited to relatively shallow formations
|Figure 1. During a May well stimulation operation, BJ crews used a new ultralightweight proppant slurry to fracture the Dakota formation in northwestern New Mexico.(Graphics courtesy of BJ Services)
because of stress and temperature limitations. A new generation of ultralightweight proppants (ULWPs) allows their use in deeper formations, where initial case histories have achieved production improvements rivaling the outstanding results experienced with the first-generation ULWPs.
Better fracture conductivity
The San Juan basin comprises an 18,000-sq-mile (46,620-sq-km) circular area in northwestern New Mexico and southwestern Colorado and is one of the most prolific gas-producing regions in the United States. The major formations are the Fruitland coal and the Pictured Cliffs, Mesaverde and Dakota sandstones. More than 300 operators have produced some 31 Tcf of gas from the basin since its discovery in the 1920s.
Despite their “unconventional” nature, the Mesaverde Group sandstones, approximately 5,000 to 6,000 ft (1,525 to 1,830 m) deep, have been reliable producers for decades, yielding good production results from conventional slickwater fracture stimulation using typically 80,000 lb of natural sand in 84,000 gallons of fluid per stage, with typically two stages per well, pumped at about 100 bbl/min.
In 2004 the stimulation design changed because of extraordinary production results being seen in the Permian Basin after fracture treatments using slickwater with LiteProp ultralightweight proppants. Theory, laboratory work and field experiences suggested the novel proppants were reaching much deeper into the formation without settling and achieving unusually high conductivity by forming partial proppant monolayers.
In a full proppant monolayer, grains are tightly packed. A partial monolayer has open areas around and between proppant particles. In 1959 Darin & Huitt (SPE 1291) calculated that sands achieve an ideal partial monolayer concentration between 0.03 and 0.06 lb/sq ft; a more typical field proppant concentration for normal sand is 1.0 lb/sq ft. They also calculated that conductivity of a partial monolayer is superior to proppant layers up to about 10 to 12 layers, which corresponds to a sand concentration of about 3 lb/sq ft. Few oilfield applications reach such high proppant concentrations. However, this fact was irrelevant for some 40 years because until ULWPs arrived, few oilfield applications could achieve proppant monolayer concentrations either.
Introduced in 2003, ULWPs are ideally suited to slickwater fracturing treatments. With specific gravity as low as 1.25, the first-generation proppants are essentially neutrally
||Figure 2. The ultralightweight proppant slurry performed as expected, resulting in excellent fracture conductivity and gas production.
buoyant in typical field brines (~1.2 sg), thus improving effective fracture length compared with conventional proppants. First-generation proppants were limited by their strength, but they worked very well in reservoirs with closure pressures up to 5,000 psi and bottomhole temperatures up to 225ÞF (107ºC). Furthermore, in a properly engineered fracture treatment, they routinely achieved proppant partial monolayers, greatly enhancing fracture conductivity compared with conventional sand fracs.
In an effort to translate the Permian Basin results to the San Juan basin, BJ engineers developed a stimulation design for the Mesaverde sands. A typical design comprises 10,000 lbs of ULWP in 84,000 gal of slickwater per stage, with the same two stages and 100-bbl/minute rate as the natural sand/slickwater fracs. The production results were excellent, increasing production by some 15 to 20%. As a result, one San Juan basin operator made the ULWP design its standard for fracture stimulations in Mesaverde sands.
Deeper, hotter, more stressed
Operators soon began looking to the deeper, more thermally mature Dakota tight gas sands, which underlie the Mesaverde formations by 2,500 ft (762 M) or more. However, closure stresses in this formation exceeded the strength limitations of first-generation ULWPs.
Instead, the service company designed a crosslinked, foamed fluid system that used sand, resin-coated sand and other proppant options in an effort to optimize fracture length, proppant transport and conductivity in the highly variable Dakota sands.
More recently, the availability of new-generation LiteProp 108 proppant and the Liquid LiteProp slurry system once again changed the “standard” of fracture design.
Capable of withstanding closure stress to 6,500 psi, the proppant offers an ultralightweight alternative for the Dakota sands. In addition to being stronger, the 14/40 sized, nearly perfectly round, smooth particles reduce drag compared with other proppants, including older ULWPs.
However, the reduced specific
gravity of the new proppant further exacerbates existing challenges with loading and blending the lightweight material and measuring the extremely small slurry concentrations during treatment. Typical frac metering equipment uses a nuclear densiometer to measure the difference in density between the carrier fluid and the proppant, but this instrument is not adequate when densities are too close, as with ULWPs and slickwater.
To overcome these challenges, service company scientists developed slurry technology that allows preparation of the concentrated proppant slurries at the district and transport to location for pumping “as is,” diluted with water or linear gel, or as foam. Therefore, on location a mass or magnetic flowmeter can be used to accurately meter the concentrated ULWP slurry into the slickwater brine fluid much in the way a liquid additive system is used.
Meanwhile, the company designed a treatment for a well about 30 miles (48 km) northeast of Farmington, N.M. (Figure 1). The well was perforated across an interval about 235 ft (72 m) thick around 8,000 ft (2,440 m) deep. The job started with an acid breakdown treatment, then followed with 76,000 gal of slickwater and 10,000 lb of LiteProp 108 proppant ramped at concentrations of 0.05 to 0.3 ppa (compared with a typical slickwater/natural sand frac at 6 to 8 ppa).
Unlike the Mesaverde fracs, the Dakota treatment was pumped at a reduced rate of 50 bbl/minute to limit fracture height growth and avoid a water-bearing zone that lies just below the Dakota in this area. Figure 2 models the resulting fracture conductivity and proppant concentration.
The formation tested at 3.4 MMcf/d to the atmosphere. It is currently producing at 700 Mcf/d at a flowing tubing pressure of 1,800 psi because of surface equipment limitations. In comparison, production from four direct offset wells ranges from nothing to 100 Mcf/d at a flowing tubing pressure of 0 to 74 psi.
An opportunity opened to try the lightweight material in the Mesaverde sands just a week after the Dakota stimulation treatment. The operator chose to perforate the Mesaverde sands in the same well, then stimulated the well using the Dakota design but at a rate of 100 bbl/minute because the Mesaverde is bounded by shale.
Initial production results from the Mesaverde zone were comparable to the earlier ULWP fracs; extended production rates will determine the ultimate effectiveness of the treatment.