Effective chemical treatment programs can save deepwater operators millions of dollars.

Production of oil and gas in deep waters has greatly expanded in recent years. At depths greater than 2,000 ft (610 m), the water temperature typically is near 40°F (4.4°C). Low temperatures can create a variety of flow problems in the mixed production flow line connecting the subsea wellhead to the production facility. Advanced chemical inhibitors and a customized chemical treatment program can help maintain oil and gas production and inhibit corrosion.
Deepwater flow problems
Waxes, asphaltenes and hydrates can cause blockages in production equipment and pipelines. Some crudes contain paraffin waxes, which can gel the crude upon cooling or deposit on the cold pipe wall surface, gradually choking off flow through the pipeline. Other oils contain asphaltenes, which can destabilize from changes in pressure, temperature or oil composition, leading to asphaltene deposits on pipe walls with subsequent plugging. Icy clusters known as hydrates, which result from the interaction of water with methane and other components of natural gas, also can cause pipeline blockage. The risers in deepwater platforms can introduce conditions that may result in severe slugging and corrosion.
Producers use a variety of mechanical means to keep pipelines free from plugs and solids accumulations. These include insulated or heated tubing and pigging devices, which fit the inside diameter of the pipe and scrape the pipe walls as they are pushed through the pipe by pumps. For effective flow assurance, pigging needs to be supplemented with a suitable chemical treatment program.
In addition to selecting the optimum treatment, it is important to determine the treatment rates, pump sizes and line diameters through phase-behavior modeling of the pipeline fluids.
Chemical inhibitors have been successfully applied in deepwater oil-producing facilities to inhibit paraffin, asphaltene, hydrates, corrosion and formation matrix scale. Custom-designed combination products may be used to perform multiple functions for a given location. Table 1 presents key success factors in designing chemical programs for deepwater applications.
Hydrate inhibition
Hydrates can form at cold temperatures in gas and oil gathering and transmission systems. Catastrophic deposition of hydrates can cause shut-ins, lost production and supply disruption.
Historically, the most common chemical additives used to control hydrates in gas systems have been alcohols such as methanol, ethylene glycol and triethylene glycol. Classified as thermodynamic inhibitors, these chemical additives function just as anti-freeze in an automotive radiator. A thermodynamic inhibitor shifts the hydrate formation curve (Figure 1) to the left such that lower temperatures and higher pressures can be tolerated when the inhibitor is present. The greater the amount of subcooling (i.e., the more severe the potential hydrate problem), the more inhibitor is required for hydrate control. Often, a significant expense is associated with the cost of "lost" methanol. This is due to the fact that, especially in low water-cut systems, chemicals such as methanol will readily dissolve into the oil and gas phases rather than partitioning to the brine phase where they can inhibit hydrate formation.
A class of kinetic inhibitors was introduced 10 years ago. Most commercial kinetic hydrate inhibitors are polymers. A kinetic inhibitor is only capable of delaying hydrate formation. As the degree of subcooling increases, greater dosages of kinetic inhibitors are required, causing this method of treatment to become less cost-effective than methanol. If conditions become severe, kinetic inhibitors often are unable to retard hydrate deposition, regardless of how much product is applied.
Baker Petrolite has introduced a third type of hydrate inhibitor referred to as an anti-agglomerant. An anti-agglomerant allows some amount of gas hydrate to form, but as very tiny, nonadherent particles that are easily dispersed in the water and liquid hydrocarbon phases. Whereas greater dosage rates of thermodynamic and kinetic inhibitors are required as the conditions become more severe, an anti-agglomerant treats at a constant dosage, regardless of the degree of subcooling (Figure 2). This makes the economics of anti-agglomerant use attractive in severe hydrate-forming conditions.
A recent flow assurance project concerned a deepwater tension-leg platform with two dry tree wells that had become rate-limited with methanol and had water cuts of 4% and 11%, respectively. The shut-in protocol was long and complicated, and the risk of forming hydrates during start-up was high. The company charged the line with three drums of its anti-agglomerant inhibitor and shut in the wells for 6 days. The wells then were restarted without plugging, and the start-up process was decreased by 12 hours. Accelerated production of 7,5000 bbl was achieved.
Asphaltene inhibitors
Asphaltene inhibition helps prevent asphaltenes from depositing upon depressurization of the crude oil during production. In conventional wells, producers use remediative methods that rely on a mixture of solvents and dispersants. Such methods are likely to be uneconomical with deepwater and subsea systems. New chemical treatments designed to inhibit asphaltenes are available for deepwater applications.
Since downhole deposition of asphaltene often is the result of the destabilizing effects of oil depressurization as it is produced, a method based on the depressurization of live oil is more accurately predictive of inhibitor behavior in wellbores. For this reason, high-pressure equipment used to determine thermodynamic properties at high pressure and temperature was used to study asphaltene inhibition. The procedure involves placing the live oil inside the high-pressure cell and slowly depressurizing at a stepwise rate until the bubble point is reached. A laser beam passed through the cell monitors changes in transmittance caused by asphaltene flocculation, changes in oil density and evolution of gas (bubble point) as the oil is depressurized. The cell then is emptied of oil, and the asphaltenes deposited on the inside walls recovered and quantified with a toluene wash followed by stripping and washing with heptane.
This method has been used successfully to develop and select asphaltene inhibitors for deepwater oils. As an example, a test was performed on 25 API gravity deepwater Gulf of Mexico crude containing 5.6% asphaltenes. The asphaltene began to precipitate from the oil at a pressure 7,000 psi above the bubble point. The test results showed that with 500 ppm of treatment chemical in the oil, the amount of deposited asphaltene was reduced 76%.
Paraffin inhibitors
Paraffin inhibition lowers the pour point to prevent oil gellation (most often to avoid restart difficulties) and prevents wax deposition on cold pipewall surfaces. The thermal and shear history of an oil have a profound effect upon the laboratory-measured pour point. To properly erase thermal history, most oils must be heated to temperatures well above the cloud point and held for some time before all of the paraffin crystals are fully melted. Standard ASTM methods such as D-97 and D-5853 are adequate for most crudes when conditioning is done at 160°F (71°C) for one hour.
Corrosion inhibition
Corrosion inhibitor programs for deepwater subsea environments must perform under harsh conditions. Since subsea wells are difficult to treat and mistakes are costly, computer modeling and laboratory protocols are used to select optimum chemicals for wells and flow lines. For example, multiphase flow modeling and corrosion-risk assessment programs are used to identify the locations that require corrosion control in a subsea system and to specify the most severe conditions under which corrosion inhibitors must perform. To run a multiphase flow model, a significant amount of information is required, including the system layout and topography; gas phase compositions; specification of the heavy fraction, water and condensate production rates; water and oil composition; and the internal diameter and thickness of the pipeline.
For each segment, the pressure drop, composition and amount of different phases, flow regime and velocities of each phase are calculated. The shear stress on the pipe wall is calculated from the frictional pressure drop.
The model results indicate temperatures at the wellhead fall from 150°F to 40°F (66°C to 4°C) over a distance of 15,000 ft (4,572 m). An aqueous phase exists even at the highest temperatures, increasing the risk of corrosion at the wellhead. As deep-sea ambient temperatures are reached, a light hydrocarbon phase condenses, which may affect partitioning of the inhibitor. The model also illustrates that pressures at the wellhead are high (5,400 psi), which means the gas may become supercritical and behave like a solvent liquid.
The basic tests used to determine corrosion inhibitor compatibility with system fluids and facilities screen the range of possible inhibitors that may be effective. More exhaustive tests, such as the static mud bomb test and material compatibility tests, measure inhibitor stability under severe conditions and the inhibitor's compatibility with system facilities.
Remote chemical monitoring
In appropriate deepwater applications, chemical treatment can be automated through a remote chemical pump control and monitoring system. Baker Petrolite's SentryNet system consists of a pump control module and remote communications technology for real-time monitoring of treatment parameters, including process flow rate, pressure, temperature and injected flow rate. The chemical treatment rate can be adjusted remotely as process needs change.
The system recently was installed aboard several remote platforms in a sour gas field in the Gulf of Mexico that was experiencing repeated shut-ins due to inadequate performance of the H2S scavenger chemical injection system. Analysis of the situation indicated the chemical pumps were set at an arbitrarily high rate to account for upsets and excursions. With the system in place, customer technicians were able to respond to process upsets remotely from a manned platform. With the reduction in chemical usage, the customer saved an additional US $186,700 a year.