No Risk, No Reward
Unlocking Huge Value with Calculated Hydrate Risk Management
In our daily lives, we constantly take calculated risks—from getting into a car to playing our favourite sport, almost every activity we pursue involves some level of risk. Most people don’t think twice about getting into a car every single day, despite there being a 1 in 93 chance that we will die in a car crash during our lives1. But why is that? It is because we have weighed the likelihood of this occurring against the consequence of walking for hours and deemed it acceptable.
Building on the theme of risk that Asher introduced earlier this week (see link below), I will delve into the specific challenges of hydrate risk and explore opportunities to optimise subsea architecture through risk-based hydrate management strategies.
A Risk Based Approach
Risk Management in Engineering
Risk management is crucial in all aspects of engineering. Engineers constantly quantify the likelihood of events and their potential impact on people, the environment, and cash flow. This approach works well when we can predict events with some level of confidence, such as the likelihood of failure due to maloperation and the consequences of a rupture and loss of containment.
However, predicting the likelihood and consequence isn't always straightforward. This is particularly true in the case of hydrate blockages in the oil and gas industry2.
Traditionally, engineers have adopted a conservative approach to hydrate management, avoiding the hydrate equilibrium region for all anticipated operating modes. This strategy, while safe, results in high CAPEX and OPEX due to investment in mitigation technologies such as heated pipelines and MEG regeneration systems.
Breaking Down Hydrate Blockage Risk
To break down the hydrate risk, we need to look at the consequence and likelihood of a hydrate blockage event.
Consequence
The consequence, in oil and gas terms, is usually broken down into the following elements:
Safety: Risk to human life, ranging from minor injury to mass casualty events.
Environment: Impact on the environment, from minor loss of containment to large-scale discharges affecting widespread ecosystems.
Production: The economic impact of production deferment, including downtime duration and associated costs.
In hydrate management, the primary consequence is downtime, as hydrate blockages typically don't pose significant safety or environmental risks (if remediation is performed diligently). In fact, reducing the use of hydrate inhibitor chemicals can lessen environmental impact of the project by reducing chemical discharge via processed water streams. Thus, the consequence rests almost solely on potential downtime, this immediately reduces the overall apparent risk.
Likelihood
Now the tricky bit. How likely is a blockage to form that will interrupt production?
Predicting the likelihood of hydrate blockages is challenging due to three key factors:
Kinetics: Hydrate blockages develop over time and in phases. In gas-condensate systems with over 90% gas fraction, this process can take hours or even days, depending on the system and operating conditions.
Hydrate Stability: The formation of hydrates is a stochastic phenomenon and hydrate formation conditions can’t be predicted with confidence. Immediately below the hydrate equilibrium curve (see below) is known as the meta-stable region where conditions are thermodynamically favourable for hydrate formation; however, hydrate formation is unlikely due to low driving force (i.e. subcooling).
Fluid Dynamics: The rate and magnitude of hydrate agglomeration in a system is dependent on the mass transfer driving force and the multiphase flow behaviour in the system. The behaviour of multiphase systems is notoriously difficult to predict accurately, even before adding hydrate prediction into the mix!
In recent decades, academic institutions and industry joint ventures have been investing heavily into hydrate research to better understand the mechanics of this process and better enable hydrate blockage prediction. This has enabled forward thinking operators to adopt a risk-based approach to hydrate management, whereby some short-term ingress into the hydrate region is allowed, with the knowledge that the blockage likelihood is low.
Case Study: Risk-based Approach
Pontem Analytics have recently completed work on a gas-condensate subsea development concept applying a risk-based strategy to challenge the incumbent hydrate avoidance strategy and potentially unlock $100’s MM in CAPEX saving with ongoing OPEX savings throughout field life.
The following approach was taken to quantify the likelihood of forming a blockage:
Water hold-up: Limited formation water production in gas-condensate systems results in low in-situ water hold-up. Operators often consider water hold-up of less than 10-20% as posing a low risk of full-bore blockage.
Hydrate Propensity: Small subcooling below hydrate equilibrium temperatures reduces the driving force, and induction time, for hydrate formation. Subcooling of less than 6 ℃ is generally considered lower risk depending on the fluid and associated conditions.
Pipeline Size: Due to the kinetics of hydrate formation, larger pipelines take longer to form blockages. A recent study of blockage occurrences performed by Pontem Analytics revealed that only 1 in 29 in the random sample set had occurred in a pipeline size of 18 inch, or greater.
Duration: Hydrate blockage formation is a kinetic process that takes time. Short-term ingress into the hydrate region doesn’t typically result in production interruption.
The criteria above are not fixed rules, and all results require interpretation by experienced flow assurance and production engineers to give confidence to the strategy.3
Proposed Management Strategy
Much like wearing a seatbelt when driving, we aim to mitigate the risk as much as possible with a hydrate management operations strategy. The following hydrate management strategy was proposed for the system:
Normal Operation: The subsea system is insulated to remain outside of the hydrate region during normal operation. Continuous long-term operation in the hydrate region presents a high blockage risk and is not permitted.
Shutdown: Sufficient insulation to allow a cooldown window outside the hydrate region. The cooldown time is only calculated in pipe sections which have a high in-situ water hold-up of greater than 20 vol.%. The small-bore subsea production system pipework (i.e. wells, jumpers, manifolds etc) is flushed with Thermodynamic Hydrate Inhibitor (THI) to eliminate the hydrate risk in these sections.
Depressurisation: Depressurise if the in-situ water hold-up exceeds 20 vol.%, this water is not inhibited with THI, and the cooldown time has expired. Depressurisation is performed to below hydrate equilibrium pressure at ambient sea water temperatures.
Repressurisation: The system is repressurised prior to restart to minimise JT cooling across the well chokes on restart. The system is repressurised with hot, dry, gas to reduce the hydrate risk.
Restart: Regardless of whether the system has been depressurised or remained pressurised during shutdown, THI is temporarily injected at the wellhead until the subsea system has warmed sufficiently to operate outside the hydrate region.
For planned shutdown, the system is inhibited with THI prior to shutdown to ensure it is inherently safe from hydrate blockage.
On a long term shutdowns which exceed numerous days the system will be depressurised out of the hydrate region, irrespective of water hold-up, to minimise the hydrate risk.
Quantification of Blockage Likelihood
The greatest hydrate blockage risk occurs during restart when the pipeline is cold, uninhibited, and experiences high turbulence (i.e. high mass transfer driving force). The plot below shows the hydrate propensity observed in the system with a 20 vol.% water hold-up criteria applied (i.e. if the in-situ water hold-up is < 20 vol.%, the hydrate propensity is reported as 0 ℃).
Despite the system entering the hydrate region coincident with >20 vol.% water, the amount of subcooling is low (< 6 ℃) and the duration is less than 4 hours in a large bore pipe section. Therefore, the risk of forming a full blockage is deemed low.
To further quantify the blockage risk, the simulation was re-run with the University of Western Australia (UWA) Gas-Dominant OLGA Extension V1.0 (shout out to Bruce Norris and Zach Aman from UWA for helping out with this!). This extension attempts to quantify the amount of hydrate which forms and deposits on the pipe wall. Unlike other kinetic hydrate prediction modules such as CSMhyK, this module is specifically designed to predict hydrates in gas dominated systems.
The kinetic hydrate modelling demonstrated a reduction in apparent internal diameter of the pipe of ~4 %. This quantity of hydrate is too low to impact the hydraulics of the system and cause a production upset.
Conclusions
This study was the initial screening of the risk-based hydrate management concept. To further de-risk the system, ongoing analysis including laboratory testing will be performed. If the system passes these tests, the rewards could be significant both for the project and for the future of hydrate management strategy for the industry.
At Pontem Analytics, we combine cutting-edge research with practical experience to deliver innovative solutions in flow assurance. Contact us today to learn how our risk-based approach can unlock significant value for your projects.
Aman, Z, Hydrate Kinetic Predictions in Gas Dominant Production, 7th March 2024.