Design and development of deepwater wells occurs over periods of several years, especially when new technologies are required to withstand unusual pressure and temperature stresses from the formation. The goal is to ensure that when the well is completed and handed over to the production team, it is a reliable, safe, and productive asset for some calculated lifetime.

Planning for deepwater wells should include consideration of technologies for flow assurance, minimizing production blockages, such as the scale deposition shown her. (Images courtesy of BJ Services Co.)

Production chemistry and flow assurance can become lost among larger concerns for safety and hardware longevity, but the effect of this shortsighted approach can have significant and lasting economic effects. Production can be shut in while salt, hydrate, scale, or other blockages are cleared. Tubulars and other downhole equipment can corrode, leading to premature well abandonment or workover. In gas wells, liquid loading can reduce production to intermittent bursts, far below the well’s potential.

The cost of building and remediating wells increases with water and well depth, making it particularly important for operators in deep water to consider potential production issues — and their ideal chemical solutions — as part of an integrated field development and production plan.

What to do when production stops

Although maximizing hydrocarbon production is the goal of oilfield development, high-producing wells also increase the chance of encountering a variety of stumbling blocks, most of them caused by pressure and temperature changes. Blocks that occur in deepwater wells include salt, hydrates, scales, emulsions, paraffins, and asphaltenes. Typical locations include the perforations, around completion jewelry, at the mudline or the coldest point on the way up to a surface tree, and at flowline junctions.

Long before shutting in production, these deposits can cause a cascade of problems. First, due to flow area constriction, these deposits change the normal pressure and temperature conditions in the well, allowing additional deposits. This constriction also reduces the effective internal diameter of the tubulars, reducing production potential. Finally, when a block is severe enough in a gas well, produced water can load up the well, requiring assistance to lift those fluids out of the well.

To minimize risks, many operators design completions with InsulGel temperature-insulating fluids in production annular areas where deposits may be likely to form. These fluids are designed to minimize temperature changes in the well, even when the well must be shut in for some period due to pipeline issues, safety valve testing, etc.

Ice-Chek hybrid hydrate inhibitor (HHI) minimized the volume of methanol required to maintain production in a Gulf of Mexico well (from SPE 96418).

When such precautions are not possible or practical, production chemical systems can prevent or sometimes remediate downhole problems.

Hydrate solutions address

deepwater issues

Among the most common downhole blockages encountered in deepwater wells around the world are gas hydrates. Gas hydrates form in cold climates, in deepwater environments, or in any point in a gas system where the gas, water, pressure, and temperature conditions are positive for hydrate formation. When a hydrate forms, a gas molecule (methane being most common in Type I hydrates) is trapped within a water molecule. As the resulting lattice accumulates and gains mass, it can block the tubing, flowlines, pipelines, or other conduits through which the produced gas flows. Under the right conditions, any gas-producing system can be vulnerable to disruption from uncontrolled hydrate formation.

The most-used solution to hydrate problems is methanol, which uses thermodynamic action to inhibit or melt hydrates. However, in practice, a surge

of water or gas production or other changes in production pressure/temperature can overcome a standard volume of methanol. Increasing the methanol flow to match surges is typically impractical and can create environmental concerns in discharge water or pipelines, corrosion issues, and safety concerns because of the fluid’s flammability during handling. An increase in the methanol volumes can also force an operator to shut in gas production in order to avoid pipeline capacity issues.

Glycol, another chemical with thermodynamic action on hydrates, is much more expensive than methanol. It benefit is non-flammability. Because of its cost, operators who use glycol also typically employ reclamation equipment so that it can be reused, which occupies valuable space on an offshore platform.

Another option is to inhibit the hydrates from forming by injecting a specialty chemical upstream of the hydrate-forming conditions. For example, low-dose hydrate inhibitors (LDHIs) use kinetic and/or anti-agglomerant chemistry to inhibit hydrate formation. They work at very low injection rates, requiring specialized pumps and plumbing. Their main disadvantage is that they cannot dissolve hydrates that form if their pumps fail, for example, or if well conditions change — for example, if production has to be shut in for several hours.

BJ Services’ patented Ice-Chek hybrid hydrate inhibitor blends compounds with thermodynamic, kinetic, and anti-agglomerant chemistry. Its synergistic triple chemical action efficiently produces a “slow-to-form” phenomenon: It limits the rate of hydrate crystal growth, discourages accumulation of any crystals that do form, and melts any that escape the other chemical actions. In the field, this “slow-to-form” attribute provides operators with a much wider window to adjust chemical feed rates if needed to overcome unanticipated changes in well pressure/temperature. In addition, the fluid significantly reduces the methanol volume required to maintain flow assurance, which improves operating expenses and well economics.

Strangled production can occur

A number of other production problems can strangle a well. For example, salt deposition is particularly severe in wells producing highly saline (>200,000 mg/l) formation brines or brines near saturation with respect to sodium chloride.

As with other scales, the potential for generating large quantities of halite scale increases as produced fluids rise in the well bore and cool — precipitating salt from solution and forming salt bridges in the flow system. Diluting the production stream with fresh water will limit deposition, and fresh water washes can remove deposits from the well bore, but logistics and economics typically preclude frequent use of these tactics. Instead, a much smaller volume of a chemical inhibitor such as Saltrol fluids or SaltSor solid granules can be injected or pumped downhole to treat produced fluids before they cool, preventing deposition.

Similarly, other scales, paraffin, asphaltene, and emulsions can deposit and build up in hydrocarbon flow paths. Therefore, inhibitor families are available to solve a wide variety of production concerns: Wax-Chek fluids and ParaSorb solids for paraffin issues; Scaletrol fluids and ScaleSorb solids for scale issues; Paravan fluids to disperse emulsions; etc.

It’s critical that these chemicals reach the produced fluids before they can begin to cause flow-assurance problems. One solution is the InjectSafe system, which provides a clean, safe pathway from the surface to the perforations, even in wells that require a subsurface safety valve. The system can be installed as part of an initial completion or added later as a wireline-retrievable replacement to a locked-out tubing-conveyed safety valve.

The availability of both solid and fluid inhibitors for many of these tasks adds another dimension of prevention: the ability to begin the inhibition effort deep in the formation. Active chemicals in the Sorb family of inhibitors are imbibed on a solid matrix, so they can be pumped with proppant or gravel during well completion to provide long-term inhibition. This means produced fluids are inhibited before they reach the near-wellbore area, the perforations, or other deep areas where temperature and pressure changes might otherwise allow deposition to occur.

There is a chemistry solution for almost any flow assurance or corrosion challenge. Many are proactive, meaning that their application can prevent the problem from occurring in the first place. Often, continuous low-volume treatments of chemicals can forestall problems altogether.