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MARCH

2016 | EXPLORATION | DRILLING | PRODUCTION

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Nabors: Energizing the drilling industry with RigtelligenceSM for the Future

MARCH 2016 EXPLORATION | DRILLING | PRODUCTION

DR. JAKE DAVIES, PERMASENSE, UK,

DEMONSTRATES HOW CONTINUOUS,

REAL TIME INTEGRITY INSIGHT

FACILITATED ASSET CONSOLIDATION

AND SAFE LIFE EXTENSION FOR A

MATURE GAS FIELD.

In 2010, a Dutch major commenced operations to extend the life of a major production platform in the Southern North Sea (SNS). One of the main technical

challenges of the project was repurposing the existing dry gas facility to handle wet gas inflows from adjacent assets and managing the subsequent corrosion risk.

The chemical inhibition strategy was enhanced to mitigate corrosion in these specific components. As part of the improved strategy, Permasense wireless ultrasonic thickness measurement sensors were installed to monitor metal loss

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58 | Oilfield Technology March 2016

at critical locations. The simple visualisation interface allowed the operator’s onshore corrosion management team to view the wall thickness data in real time and, if necessary, modify the inhibitor injection rates to ensure safe, continual operation of the platform.

Mature gas fields, ageing assetsWith margins squeezed, gas producers in every region are focusing on maximising output from existing assets and doing more with less. However, as gas fields mature, the associated infrastructure often requires a level of reconfiguration or repurposing to maintain its integrity and profitability.

An increasingly common challenge faced by operators of mature fields is the desire to reduce operating expenditure (Opex) by increasing the number of normally unmanned installations (NUIs). This can involve the removal of compression and/or gas drying capabilities on previously manned platforms, and repurposing larger assets to handle wet gas instead of dry.

As a field matures, additional wells are often drilled and brought on-stream to maintain production capacity. Sometimes this results in local bottlenecks and the existing facilities are modified to reduce their effect. The situation can be complicated further by additional modifications required to keep the gas flowing from existing wells as the pressure falls off towards the end of economic field life. For example, compressors can require changes in their input stages to work with lower arrival pressures resulting in additional re-routing to avoid flow-back conditions.

This reconfiguration work, combined with the increasing volume of formation water typically produced from ageing wells, requires a robust corrosion management strategy. If undetected and unchecked, corrosion can have a major impact on asset integrity, resulting in expensive repair work or even loss of hydrocarbon containment – the environmental, safety, financial and reputational implications of which can be catastrophic.

Corrosion monitoring and control then, is no longer just ‘nice to have’. Constant monitoring is essential in order to

manage the associated risks effectively. Therefore, operators need tools and data that can deliver insight and, importantly, actionable information to achieve the desired outcomes.

Project backgroundThis case study is based on a recent life extension project for a mature field development in the Dutch sector of the SNS. Operational since 1975, the development includes two large hubs receiving gas from a number of satellite platforms, which feed the hydrocarbons into a principal platform.

Over the last decade, the operator has implemented a strategy to extend the economic life of its producing assets by consolidating existing infrastructure and streamlining its operations. As a mature field, declining production and rising operational costs needed to be balanced with maintaining the integrity of the assets and the associated infrastructure. Improving the wet gas handling capabilities of the principal platform made it possible to ‘simplify’ the associated hubs and satellite platforms, which would reduce the need for future manning.

The challengeAs part of the consolidation process, the principal platform was reconfigured to handle wet gas inflows from the adjacent infrastructure. Maintaining asset integrity – and therefore optimum output and safety – was the absolute priority, but this created a number of new technical challenges.

The carbon steel pipework intended to transport hydrocarbons between the principal platform and its sister facilities was originally designed to handle dry gas. The challenge with wet gas is that the water phase is acidic because it contains CO2 and organic acids. Therefore, corrosion was a particular concern from the outset.

To address this risk, various equipment and valves were replaced with corrosion-resistant alloys. However, it proved too complex and

Figure 1. Data delivered directly to desk for visualisation and analysis.

Figure 2. Non-intrusive sensors are installed on-stream.

March 2016 Oilfield Technology | 59

resource-intensive to replace some of the existing carbon steel infrastructure – an option that would have almost certainly rendered the project uneconomic. The operator needed to find a way to operate safely within the limits of the existing infrastructure.

Part of the solution included improvements to the existing chemical corrosion inhibition strategy, providing additional corrosion inhibitor injection points. However, there is a very fine balance to strike: if excessive corrosion inhibitor is added without sufficient liquid water in the stream, the raw inhibitor itself becomes corrosive to carbon steel. Therefore, it was critical that the new injection points were only added when the process fluid reached certain levels of wetness. If too much inhibitor was added too early then it could actually increase the risk of corrosion instead of mitigating it.

To try and achieve that balance, the operator installed intrusive probes to monitor the effectiveness of the corrosion inhibitor. These probes protrude into the flow, and gauge the corrosivity of the fluid by measuring corrosion of the sacrificial element of the probe.

The crucial drawback of such a system is that it can only infer corrosion levels – what the probes are actually measuring is the loss of metal from the sacrificial element of the probe inside the fluid stream. The corrosion rates of the pipework itself are then estimated from the corrosivity measurements.

Estimating though, is not the same as measuring, and the operator needed more accurate insight into the levels of corrosion in its pipework, and in more locations. The more complete the picture, the more confident the operator could be of the safety and integrity of the asset.

As Dr. Peter Collins, CEO of Permasense, explains: “There is such a thing as best practice with inhibitor levels, but there are so many uncontrolled variables that it is an inexact science. It is perfectly possible that the chemicals are within recommended levels but internal corrosion is still occurring. In that case, it is necessary to either invest resources in frequent manual checks, or risk discovering the problem when it is too late. The way to avoid that is direct measurement – Permasense’s sensors do this, and can deliver those measurements directly to desk.”

The solution: continuous integrity monitoringAt the heart of the monitoring systems are sensors that employ proven ultrasonic wall thickness measurement principles. These sensors are affixed to the external surface of the pipework to determine the thickness of the pipe wall by continuously monitoring for metal loss at critical locations. The technology is non-intrusive and wireless, meaning it can be installed while assets are on-stream without expensive cable runs to retrieve the data. This solution also offers users

the flexibility to deploy sensors in close proximity or spread across an asset.

“Without the Permasense sensors, the only way to access this level of information would be for inspection teams to collect the data manually – substantially increasing the costs and safety risks associated with accessing the pipework. A system that could continuously and wirelessly transmit corrosion data back to the operator was therefore the most operationally effective and commercially attractive option” explains Collins.

ImplementationThe final solution employed at the SNS asset included 30 WT100 wireless thickness sensors. Corrosion monitoring locations were selected in high risk areas of the pipework, and sensors were installed to give the operator continuous, accurate insight into the actual levels of corrosion occurring.

The original proposal was to install the technology using studs to affix the sensors to the exterior of the pipework.

Figure 3. Senors installed in arrays to monitor for localised erosion or corrosion.

Additional information

Ì Direct measurement of corrosion on the pipe work, rather than corrosion-prevention, means more reliable, actionable and timely data.

Ì A flexible, wireless and non-intrusive system means a quicker, cheaper installation, even when on-stream, and allows for future re-deployment of sensors.

Ì Automated, wireless data acquisition means zero Opex for repeat measurements or manual inspection costs, and no risk to personnel.

Ì Accurate and direct data on equipment corrosion delivered directly to desk allows for a higher safe flow-rate, which in turn means higher revenue in a mature field and a low price market.

60 | Oilfield Technology March 2016

However, concerns about the project scheduling meant that a clamp design was adopted as this provided more flexibility.

Real time resultsOnce installed, the WT100 sensors directly and wirelessly transmitted accurate data back to shore in real time. The simple visualisation interface allowed the operator’s corrosion management team to quickly identify changes in corrosion rates, and take remedial action to ensure continual, safe operation of the platform.

Flow-back lines are particularly vulnerable to internal corrosion attack due to the variable and often low flow rates that can allow water to gather and increase local corrosion activity. For this reason, the operator installed Permasense sensors in these and other areas of elevated corrosion risk, downstream of the first and second compression stages.

The operator deliberately left the valves on these flow-back lines slightly open to encourage adequate flow rates and replenishment of corrosion inhibitor to mitigate the elevated corrosion risk. The data from the sensors allowed the operator to validate that the existing corrosion control measures were enough to adequately control corrosion rates without the need to add further chemical corrosion inhibitor injection locations.

By directly measuring wall loss rather than just the chemistry of the fluid, the WT100 system can catch elevated corrosion rates that are having a genuine impact on the integrity of the asset, before they become too serious. The fact that the data is accurate and delivered in real time, means that the operator can quickly understand and address the underlying issues.

The installation of the sensors completely removed the need for guesswork. Data quality improved, and the continuous frequency of measurement allowed the operator to monitor changes to wall thickness as they occurred.

As a result, the operator could now rapidly and continuously monitor how the infrastructure responded to

all the unpredictable and uncontrollable variables that can affect internal corrosion within the upstream environment. The company now has the tools to monitor the effects of an unexpected change in these uncontrolled external variables, assess the precise effects of corrosion inhibiting strategies, and adjust them as necessary.

The installation of the sensors ultimately enabled the operator to maintain safe and profitable operations at this mature gas field. A number of key features made this possible: Ì Direct measurement:

h By having a direct measurement of corrosion occurring at the wall of the metalwork rather than just of the levels of inhibitor in the flow, or the corrosivity of the fluid, the operator could have confidence in the readings, meaning fewer manual inspections and unhampered production.

Ì Real time insight: h The continuous system feedback meant that the

operator could adjust for and eliminate certain variables, to swiftly address any underlying problems.

Ì On-stream installation: h The non-intrusive design of the WT100 sensors resulted

in minimal ongoing Opex costs for installation, maintenance and replacement.

Ì Wireless data delivery: h Just 5 m of cabling can require 10 - 12 different

people working on the cables in different capacities; significantly increasing the cost of installation, operation and maintenance. Permasense sensors use wireless data delivery for ease of sensor installation and ongoing data retrieval.

Ì Minimal maintenance: h The replaceable battery for the WT100 sensor provides

two and a half years of maintenance-free operations.

Common challenge: simple solutionWhile every project comes with its own specific challenges, the drivers behind this particular case are hardly unique. Whether

converting from dry to wet gas flow, handling reduced pressure from ageing wells, or removing bottlenecks, similar challenges remain. Corrosion and erosion are growing problems for the oil and gas industry and a proactive approach to monitoring will be key to maintaining safety and profitability in mature fields.

Armed with the type of technology offered Permasense, and the quality and frequency of data it delivers, operators are in a far better position to develop a cost-effective programme for monitoring the integrity of their assets. This means an instant saving on expensive manual inspections and a long-term gain in enhanced asset reliability and availability. Automated monitoring of asset integrity combined with appropriate data analysis also gives operators the confidence to drive their assets harder within the appropriate parameters, and enhance their profitability. Figure 4. Permasense sensors enable safer and optimised production.