Inhibitor package simplifies production chemistry in wet gas applications

A Nalco technician performance-tests one interation of a corrosion-inhibitor blend. Photo courtesy of Nalco Champion.

The oil and gas industry often relies on chemical solutions to address challenges related to flow assurance and corrosion inhibition. Transport of produced fluids containing water and acid gases, such as CO₂ and/or H₂S in metal pipelines, creates conditions susceptible to both gas hydrate formation and corrosion. Accordingly, production chemical strategies typically must consider a compatible corrosion inhibitor and low-dosage hydrate inhibitor as a unified package.

Standard chemical compatibility often includes the mixing of two neat production chemicals with exposure at various temperatures, to examine for hazing, phase separation, precipitation, etc. This exercise provides operators insight, in the event that chemicals are accidently mixed in storage tanks or may come into contact in delivery lines, although the performance compatibility of a KHI and a CI presents a more challenging case.

As KHI and CI formulations both contain surface-active components, the tendency for these components to negatively interfere with one another has been well documented.^1,2 The performance of the CI is often only slightly affected by the presence of the KHI. However, performance loss up to 50% for a KHI has been noted in the presence of an incompatible CI.³ Though the origins of these interactions are not fully evident, it has been theorized that 1) the separate inhibitors compete for absorption at the oil-water interface, leading to diminished effective KHI concentration; and/or 2) the CI associates with the active sites on the polymeric KHI responsible for hydrogen bonding with hydrate particle surfaces.

In addition to the requirement of chemical compatibility, secondary properties of the inhibitors must be scrutinized. As inhibition programs are often amended in the OPEX stage, the chemical’s physical properties must be developed to retrofit to the existing chemical delivery system. This often includes deliverability simulations, in which viscosity at pressure, as well as chemical density, are input to ensure that a chemical can be delivered to its injection point safely and in a controlled manner. Often, this may necessitate reformulation in a low-viscosity solvent, such as methanol, to maximize deliverability. Conversely, SH&E regulations may demand formulation in a high-flash-point aromatic blend solvent to decrease flammability. The activity, defined as the concentration of components contributing to performance, excluding solvents, of a chemical formulation, may also be driven by the existing chemical delivery system. A highly concentrated formulation may initially appear ideal, but often presents deliverability challenges. On the other hand, maintaining supply of an extremely dilute product may lead to issues of logistics, storage, and exceeding facility weight requirements. As KHIs are typically dosed on a volume percentage (vol%), while CI rates peak at several hundred ppm, both based on water production, many chemical injection pumps have difficulty achieving the high rates required for continuous KHI injection or accurately delivering the low rates of a concentrated CI.

Background. Several operators producing in wet-gas mode require a compatible KHI/CI package along with, in some cases, a batch corrosion inhibitor. The use of a KHI significantly reduces the transportation, storage and deliverability problems associated with the large volumes of thermodynamic inhibitors required for standard operation, and makes production over vast distances through networked subsea wells feasible. Corrosion control by chemical inhibition is one of the most mature and developed fields of production chemistry. Conversely, methods for non-chemical corrosion control are typically expensive, difficult to implement in the OPEX stage, and utilized in niche situations.

One scenario presented a unique set of properties and performance criteria that required an unconventional KHI formulation to be matched with a robust corrosion inhibitor. The following list represents the key performance metrics for the KHI/CI package to address the anticipated field conditions.

• Chemical and performance compatibility between KHI and CI
• KHI to prevent hydrate formation at 8°C sub-cooling, for a minimum of 200 hr
• KHI formulation to contain 80% methanol
• KHI chemical to have high cloud point (high temperature and salinity tolerance)
• Corrosion rate less than 0.1 mm/year and no localized attack
• CI formulation capable of dilution
• Low environmental toxicity (biodegradation and bioaccumulation).

For this scenario, it was the desire of the operator to have a highly dilute, dual-function KHI product. The KHI would exhibit excellent performance against hydrate formation at high sub-cooling, at standard chemical dose rates, but could also function as a THI for extended shut-ins, unplanned shut-ins, and well restarts with a modest increase in rate. This unique formulation could, additionally, be utilized to prevent ice formation from Joule-Thomson effects.

Field applications of KHIs are generally limited to a maximum 9°–10°C sub-cooling, for a hold time requirement on the order of days.⁴ On that basis, the 8°C subcooling and minimum 200-hr hold time targets were not considered particularly daunting metrics. The dilution with 80% methanol did present a unique challenge: That dilution would significantly decrease the polymer activity in the final offering, necessitating the development of a high-performing parent chemistry, which could be manufactured fairly concentrated. When dosing up to a potential 3.0vol% treatment rate of KHI, the introduction of methanol, from the KHI formulation does not substantially reduce the sub-cooling. Standard PVT modeling software estimates the reduction in system sub-cooling from methanol at approximately 0.4°C sub-cooling/wt% methanol.⁵ A secondary factor involves the formulation of the KHI offering. As KHI polymers are typically formulated in water or glycol-based solvents, the solubility of the polymer in a methanol system was not well precedented.

KHI testing equipment. KHI performance testing can be run in several pieces of equipment, as there are several industry-accepted methods for testing. Each testing method has certain features and benefits that will cause slight variations in sub-cooling, GOR and fluid agitation.⁴

In a typical test procedure, fluids are loaded into a cell and pressurized at a given temperature with test gas while mixing. Mixing is provided, in an autoclave, by an overhead mechanical mixing paddle or a magnetic stir bar coupled to a stir plate below the cell, and in a rocking cell by a stainless steel ball (sweet testing only). Fluids are saturated with gas at a temperature above the hydrate formation temperature for the given pressure. The test fluids are then cooled at a defined rate to a set point temperature. Once the temperature setpoint is reached, the timer for establishing an experiment hold time begins.

Hydrate formation, a failure in a KHI test, is noted by a drop in cell pressure (a differential of 2.9 psi, or 0.2 bar, has been set as a standard). A hold time is reported as the time differential between achieving temperature set point and failure. Data plots are typically reported with cell pressure and temperature as a function of time. Tests often include durations in which mixing is stopped to simulate a shut-in, or cell temperatures are changed to examine performance at variable sub-cooling. Cells are heated following test completion to the initial temperature at pressurization, to ensure no cells leaked during the test. Due to the stochastic nature of hydrate formation, experiments are performed in parallel to ensure reproducibility.

Regardless of equipment type, the appropriate hydrate equilibrium temperature (HET) experiments are performed prior to evaluating KHI performance to accurately determine test subcooling.^1,6,7 In a constant-volume HET experiment test, the hydrate dissociation temperature is measured by examining the plot of temperature versus cell pressure. In this test, the cell is loaded with fluids in the absence of a KHI or THI and cooled to a temperature below which gas hydrates will form. The cell is held for a defined period of time to allow hydrates to form, and is then very slowly warmed until all the hydrates have dissociated. The temperature at which the pressure trace, during the warm-up cycle, either matches or runs parallel to the pressure trace during the cool-down cycle, is considered the HET at that specific cell pressure.

Kinetic hydrate inhibitor qualification. Performance testing for this application took place in blind rocking cells, Fig. 1a. These stainless steel cells hold a volume of 40 mL and are pressure-rated to 5,000 psi. The cells do not have visual capabilities, but are attached to a manifold that controls the gas in/out with a shut-off valve, contain an analog pressure gauge, and have a pressure transducer fitting, which collects pressure data points as a function of time. The cells are mounted into a tank, which houses up to 24 cells, Fig. 1b. The tank is rocked with an oscillating table, which provides agitation to simulate pipeline flowing conditions. The rocking rate can be controlled with this table and stopped entirely to simulate a shut-in.⁴

Fig. 1. (a) Individual blind rocking cell; (b) 24 cells mounted in rocking cell tank.

The KHI/CI package was qualified with a type II hydrate-forming gas blend, field condensate, and DI water at a 30% water cut and a sub-cooling of 8°C. Blind rocking cell qualification protocol included test portions examining both dynamic and static simulations to address standard production and shut-in scenarios. A minimum hold time of 200 hr, without hydrate formation, was targeted as a pass/fail criterion. This metric would afford the operator ample time for produced fluids to travel through subsea flowlines under conditions of hydrate stability, in the absence of a traditional THI, as well as identify a “no-touch” time in the event of an unplanned shut-in.

Figure 2 displays a data plot from that qualification. As these experiments are performed under constant volume conditions, a drop in cell pressure indicates the formation of gas hydrates. The experiment begins with saturation of the cell fluids, with gas at a temperature above that at which hydrates will form, so any change in pressure upon reaching set point temperature is indicative of failure. Note that the slight change in cell pressure during the 72-hr shut-in simulation between days 1 and 4 is credited to the equipment, and not a chemical failure or cell leak. As cooling fluids are static during a shut-in, a slight temperature gradient of the water/glycol mixture in the tank can form. Upon the conclusion of the test, a slow heat-up cycle reveals a linear increase in pressure with respect to temperature, confirming the absence of gas hydrates.

Fig. 2. Experimental data plot of original qualification of KHI with CI-A; several pressure traces removed for clarity.

This original qualification required a treatment rate of 2.5vol% KHI and 250 ppm CI-A. Additional experiments were performed examining the CI-A rate at 500 ppm to probe the compatibility envelope of this package. In these experiments, the chemical package surpassed the same hold time requirements.

Due to the potential for high temperatures at wellhead injection points, and scenarios with produced water of variable salinity, a KHI solubility screen was performed. The lower critical solution temperature (LCST), or cloud point, is the critical point at which all components in a mixture remain miscible. The cloud point of KHI polymers is reduced with increasing salinity of an aqueous solution. The raising and lowering of temperature of an aqueous KHI solution, with respect to the cloud point, will reversibly take the solution in and out of homogeneity.⁴

Fig. 3. KHI solubility profile.

Procedurally, a vial containing the condensate and/or brine was heated to 90°C and mixed with a magnetic stir bar.⁶ The CI was first dosed, followed by the KHI. The mixtures were stirred for one hour at that temperature and then cooled to below 30°C. Polymer precipitation and particle sticking would call for immediate failure at any point in the test. Hazing was acceptable, as long as the solution returned to clarity upon cooling. The expectation for slight coloration or clouding upon the introduction of chemical was acknowledged. Figure 3 plots the experimental KHI cloud point versus salinity, revealing a high degree of tolerance for high temperature and brine salinity. 

COMING NEXT MONTH:

In the second and final part, the authors discuss further qualification tests for the KHI/CI package, and their application in the field.