Flow assurance problems can cause significant financial penalties due to lost production and the cost to fix them as well as representing serious HSE risks. If potential flow assurance issues are not detected early and left unmitigated, they can lead to pipeline blockages, catastrophic failures, loss of containment and shutdown. As the oil and gas industry accesses deeper waters and increases reliance on long subsea tiebacks and pipelines to processing facilities, the potential for flow assurance issues increases.
Flow assurance issues include corrosion, erosion, vibration-induced stress, liquid slugging, emulsions and the formation of different chemical deposits in pipelines including wax, hydrates, asphaltenes, naphthenates, paraffin and scales. Optimized chemical dosing is an essential strategy, along with other methods, to ensure effective flow assurance.
Chemical dosing will vary over the lifetime of a well, with the choice of chemicals changing according to the produced fluids and production rates, to ensure production optimization, asset integrity and low flow assurance risks. Therefore, it is essential to make sure the chemical balance is accurate. For example, underinjection of chemicals for scale or paraffin control can result in reduced production and hence lower profits due to the uncontrolled buildup of deposits in pipes. Ultimately, these deposits can potentially block the pipe completely leading to lost production, but even if this point is not reached, production might be halted to remove the coatings.
While under-injection might save on operational costs, it can ultimately result in reduced production, increased maintenance costs and greater risks to assets. For example, under-injection of corrosion inhibitors might result in halted production to evaluate pipeline integrity and replace affected components.
On the other hand, while over-injection of chemical additives increases operational costs, it can reduce production downtime but also can lead to issues with the effectiveness of downstream processing. Some upstream processing facilities can recover these chemicals for reinjection to reduce costs and issues for downstream processing. Operators are focused on increasing production while reducing operational costs, but must balance the effectiveness and investment in a challenging economic environment. For example, the cost of chemical injection to mitigate flow assurance issues can exceed $2/bbl of produced oil.
The development of appropriate chemical treatment programs requires samples of the production fluid. However, the collection of samples at the platform means the sample will be at different conditions as compared to subsea pipelines, adding additional measurement uncertainty from the laboratory analysis of the sample and subsequent extrapolation to subsea conditions. Other disadvantages of this type of sampling are that some chemical components might have already been deposited in subsea pipelines and therefore are not detected in topside samples, creating a major flow assurance risk.
The lack of real-time data regarding fluid composition to develop intelligent feedback systems for controlled chemical injection is a major barrier to the development of cost-effective flow assurance strategies. Instead, there is a heavy reliance on taking physical samples of the produced fluids and sending these for composition analysis. This expensive and lengthy process to obtain fluid composition is not regularly performed, despite the industry recognizing that flow conditions can change very quickly. It can take several weeks from the collection of a sample to the provision of usable data before operators allow decisions on flow assurance and chemical injections, by which time flow conditions will likely have changed.
To reduce capital costs, fluid sampling infrastructures are commonly no longer included within new field developments, but this has reduced the margins for error and increased flow assurance risks. Consequently, there is a reliance on over-injecting chemicals to eliminate any potential issues.
Chemical treatment programs to mitigate flow assurance issues might be developed that could require continuous injection; this is common for upstream production, or intermittent injection depending on requirements and flow composition. For flow assurance risks, such as hydrate control, high volumes of chemicals (e.g., methanol or glycol) might need to be injected. In the case of methanol injection, this can be up to 40% by volume of the liquid present; then this exacerbates other flow assurance issues with multiphase flows such as slugging.
Future of chemical injection
There have been some pilot investigations by research organizations into the development of new sensor technology and models that can be used successfully to indicate when flow assurance issues might occur in real time and determine accurate chemical dosing.
Research has shown in one field that, for the most part, there was no need to inject any hydrate inhibitor chemicals as the flow conditions and fluid composition were outside the hydrate formation envelope. This substantially reduced operating costs. Previously, inhibitors were continuously injected based on the worst-case operating scenario. One estimate suggests that with improved chemical management, a potential reduction in monoethylene glycol could save about UK £1 million per year for a typical single gas well.
Fluid sampling techniques need to be developed that allow online analysis in real time using robust technologies capable of operation in the field reliably and with little maintenance. Those will need to be accurate and repeatable for all flow compositions, velocities and flow patterns. Methods also will need to be established to provide a real-time breakdown of the hydrocarbon composition of multiphase flows to establish optimal chemical dosing requirements and determine the amount of water present.
Sensors will need to be developed and evaluated, or techniques using correlations linked to other sensor measurements could be developed to detect and measure the quantities of residual-dosing chemicals in different parts of a pipeline. Flow assurance models could potentially be optimized, based on the real-time data from inline sensors in long subsea pipelines and risers, and in other remote, inaccessible locations.
If new sensors were developed that can determine the hydrocarbon composition and concentration of added inhibitor chemical species in real time, this would offer a major innovation in flow assurance management, reducing measurement and modeling errors. Information on the flow conditions, such as temperature, pressure, hydrocarbon composition and water content, could be used to establish safe operating envelopes, within which no chemicals would be required. The same strategy could be applied to inhibitor chemicals for wax and scaling.
Flow assurance intervention costs could be substantially reduced by the availability of real-time data that will make it possible to rapidly identify and mitigate issues, including equipment failures and production shutdowns, and to reduce the cost and volume of chemicals required. The development of sensors and sampling to collect real-time data, combined with a more advanced fundamental understanding of physical chemistry, will deliver a significant improvement in the optimization of chemical injection programs and launch a new era in cost-effective flow assurance management strategies. Crucially, by using online analysis, this should all be possible in a way that does not increase operational risk.
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