Long-life scale inhibitors placed deep within a created fracture can inhibit scale, paraffin and other deposits that effectively choke production and promote corrosion.

The goal of stimulation is to maximize recoverable hydrocarbon reserves and increase the rate of recovery. But often the increased wanted hydrocarbons come with unwanted scale-prone water, paraffin, asphaltenes, bacteria, and other contaminants that can quickly reduce production and require expensive, repeated remediation.

Remediation typically takes the form of squeezing production chemicals into the formation or continuously injecting chemicals into the well to treat the fluid for whatever problems are occurring. In severe cases, expensive workovers are required to remove deposits, repair corrosion-damaged assets or restimulate the well to reestablish near-wellbore communication with the reservoir.

Instead, StimPlus services look ahead in the life of the well, pumping proprietary inhibitors and other chemicals deep into the formation where they can prevent contaminants from becoming costly production problems.

Inhibitor basics

Generally, chemical inhibitors prevent some unwanted material from precipitating out of produced fluids (dropping out of solution to form solid deposits). For example, a scale inhibitor prevents normal crystal growth and allows water to hold more dissolved salts than it normally would.

Inhibitors have traditionally been applied to a well in three ways:
• A continuous or batch injection stream down the annulus or through a capillary tubing string protects the well bore. This requires frequent visits to the wellsite to maintain the chemical tanks or re-inject chemicals.
• Inhibitor material can be placed in the rathole, also protecting just the wellbore and requiring frequent replenishment of the chemical.
• A squeeze treatment injects liquid inhibitor into the near-wellbore area, where it mixes with producing fluids, protecting the well bore, perforations, and near-wellbore formation. Typically, a squeeze must be repeated every six to 12 months.
In any case, well fluid samples are used to monitor the protection level provided by residual inhibitors. This helps determine treatment levels or schedule re-squeeze operations.

Three years of control

In the coalbed methane fields of West Virginia, fracture stimulation is a blessing and a curse. Fracs are essential to achieving economic gas production, but they also result in water production, increasing the likelihood of scale deposition that can reduce the benefit of stimulation in a matter of weeks.

Because the West Virginia wells are remote and marginally economic even after stimulation, these traditional applications stretched the economics for one operator. When one of the operator’s wells needed a re-frac, the job recommendation included BJ Services’ proprietary ScaleSorb solid, long-life scale inhibitor blended in the stimulation fluid with the proppant.

When pumped with the frac in a StimPlus service, the dry, granular ScaleSorb material is carried with the proppant deep in the formation, slowly releasing inhibitor into formation fluids as the well is produced (Szymczak et al., SPE 102720). This means that the fluid is already inhibited when it reaches the near-wellbore area and perforation tunnels, where pressure and temperature changes might otherwise lead to scale deposits. Importantly, the material was designed to slowly release its active chemicals, enabling scale inhibition for three years.

BJ Services pumped the frac in March 2005. To date, the operator reported that this well has had no scale-related production problems, and the well’s produced water reportedly still contains enough inhibitor residuals to protect against scale deposition. The operator now routinely includes ScaleSorb material in all fracture stimulation designs.

The same technology was recently used in a deepwater Gulf of Mexico well where the operator considered the risk of scale deposition to be minimal. However, the potential cost of remediating a scale problem in the Atwater Valley well was extremely high, so the operator pumped a StimPlus frac as a safety factor for the future of the well.

Conductivity and compatibility

The success of the long-life scale inhibitor sparked the development of long-life paraffin and asphaltene inhibitors. All are designed for maximum conductivity and compatibility with common fracturing fluids, biocides and other chemicals that may be used in stimulation treatments. ParaSorb and AsphaltSorb inhibitors have been pumped as components of fracture stimulations in the United States and in the Gulf of Mexico with a variety of fracturing fluids and other chemical products without any compatibility issues.

Compatibility was also a concern when planning a re-frac in southern Sumatra, Indonesia. The operator had complained that the well suffered from sand production that required frequent cleanouts, but lab testing of a “sand” sample found that it comprised particles of calcite scale. To control the scale problem, BJ Services designed a water conformance frac with a scale inhibitor. Lab testing found that the normal inhibitor used in that area was incompatible with the frac fluid crosslinker, so an alternative was found. Thirty days after the successful re-frac, the oil rate had increased eight-fold and the water cut had remained stable. Several months later, the scale problem had
not resurfaced.

Pre-job compatibility testing is particularly critical in stimulations that involve more than one inhibitor. For example, a number of Rocky Mountain operators must use a water source that is prone to bacteria and scale problems. Lab testing determined the best biocide and scale inhibitor combinations to ensure that the chemicals can inhibit as expected without affecting the stimulation fluids.

Barnett Shale chemicals

Similar problems occur in the Barnett Shale (Szymczak et al., SPE 107707). Although the shale does not hold connate water, stimulation fluid during a frac solubilizes mineral salts exposed from created microfractures. Depending on the water and formation chemistries, the result can be catastrophic scale deposition. Therefore, some scale inhibition is critical.

When one Barnett Shale operator added a third-party scale inhibitor to a slickwater frac job, the pumping horsepower requirement (and related cost) increased dramatically.

Laboratory investigation later determined that the inhibitor was not compatible with the frac system. Subsequent fracs were designed to include a compatible scale inhibitor and additional inhibition chemicals designed to solve two other significant production problems.

Fracture stimulation jobs typically require the use of a biocide because bacteria in frac water can attack and digest the guar used to viscosify the base frac water and “sour” the well, causing potential loss of tubular goods and other downhole equipment. Even in the Barnett Shale, where guar-based fluids are typically not used, frac water is typically treated with biocides to minimize the danger of bacterial corrosion in the well. In this case, acid-producing bacteria contributed to 90% of the failures in the field!

And yet, the standard biocide for the field’s fractures was the least effective choice for acid-producing bacteria. Laboratory testing found, however, that the most effective biocide for these bacteria was not compatible with the frac fluid system, and so another good alternative was chosen.

Similarly, oxygen introduced into the fracture zone via the frac water can result in high oxygen corrosion rates. Untreated, this problem can result in well failures and elevated operational costs due to workovers. In fact, while this frac was being planned, the operator was pulling tubulars from other wells to repair corrosion damage.

Adding a compatible oxygen scavenger to the frac fluid ultimately reduced the operator’s expenses and downtime.

Typically, operators separate drilling, completion, stimulation, and production into separate categories without considering how each step might affect the life of the well. In this case, although the stimulation cost was slightly higher with the StimPlus service chemicals than without, the holistic, forward-looking approach helped the operator increase production while reducing overall expenses, truly maximizing the effectiveness of expensive fracture stimulation
treatments.