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Living a productive life

Oilfield Technology,

Colin JB Smith, Wood Group Intetech, explains ways of ensuring the longevity of a well.

Jeanne Calment lived for 122 years and 164 days. She lived her entire life in Arles, France and is, verifiably, the oldest human being ever to have lived. Calment attributed her longevity and youthful appearance to drinking port wine, a diet rich in olive oil and eating nearly a kilogram of chocolate every week.McClintock No. 1 in Pennsylvania has been producing oil for 154 years. It is, verifiably, the oldest continually producing oil well in the world. Drilled in 1861, the well still produces 1/10 bpd.

The Calment and McClintock cases are extreme, but it is notable that their lifespans are within the same order of magnitude. Today, people and wells are both capable of living long and productive lives – for a century or more.

Figure 1. iWIT™ Well history timeline

Longevity is, in part, down to the fortune of inherent disposition. Calment undoubtedly possessed genetic traits and congenital advantages that helped her live such a long life. Well longevity is also, in part, due to the inherent disposition of the reservoir – the volume of hydrocarbon that can be recovered and the rate of this recovery.

Reservoirs are not created equal and depletion rates vary widely, but the aim for any well is to serve as a drain for the reservoir until the economic limit is reached. This relies on design and construction characteristics that can be considered inherent to sustain the life of the well for the conditions it will encounter. Produced fluid characteristics and production dynamics can change considerably over a well’s life. Therefore there is a strong reliance on design and materials selection when the well is first constructed, and throughout its lifecycle.

Figure 2. Example corrosion rate estimate for an individual well as a function of time (dark blue line) and cumulative tubing wall thickness loss (light blue line). A caliper survey result from mid-2008 is indicated by a triangle, confirming reasonable agreement with the corrosion model estimated wall thickness loss at that date.

The lifespan of a well is down to external factors such as strong pressure support from an aquifer, effective maintenance programmes, corrosion-mitigating strategies, and avoiding well component failure.

Some form of treatment is inevitable for the well at some point. Well failure or leaks to surface are obvious signs that problems exist. But some integrity issues are not necessarily acute, they are chronic and take time to manifest to a point where they become evident. To address this, a well can undertake a regular ‘diet’ of preventative maintenance and may eventually undergo an intervention.

Right treatment, right time is a mantra that doctors use to treat patients. Doctors examine, monitor, assess then treat issues at the right time to sustain life. Maintaining integrity to keep a well healthy, safe and an effective conduit for production is only safeguarded through a similar approach integrating data acquisition, monitoring and analysis to enable both effective decision-making and the ability to take the right course of action at the right time.In mature oilfields, well integrity issues lead to approximately half of well shut-ins, and half of all workovers are related to operational integrity problems. Enacting well integrity management (WIM) to tackle these challenges and ensure safe operations typically starts with the development of a plan or strategy. The longevity of wells may not be an explicit aim of these initiatives, but the provision of a safe and continuous conduit for uninterrupted production will underpin objectives.

In oil well maintenance, engineering judgement is supported by tools to identify or measure where problems lie that may impact well condition. Some companies rely on spreadsheets to manage this activity. But spreadsheets are not only difficult to maintain; one multi-industry study found that 88% of spreadsheets contain errors.

Figure 3. Review of the installed tubing in one field identifying the percentage of wells having wall thickness loss in various fractions.

Advanced WIM software systemises data acquisition and integrity management processes. With in-built data validation, these tools greatly improve data quality. These systems allow users to monitor pressures, temperatures and other parameters, and rank wells based on performance indicators or risk-based metrics. Unlike spreadsheets, they can utilise high-frequency measurements that reflect the current reality of field conditions. The result is a rapid, systematic and proactive identification of issues and production threats.

Some systems also enable tracking for the full well lifecycle. By systemising historical data from well construction, well completion changes and operational events (such as the results of tests or surveys), a full picture of well life can be captured. Like a comprehensive medical record, engineers can gain insight into the history of a well to better understand and treat issues. Properly designed systems have the flexibility to evolve just as field conditions and regulatory requirements change through time.

Services exist to do just that. For example, Wood Group Intetech’s iQRA platform allows operators to reduce well entries, establish optimum maintenance schedules, minimise corrective maintenance, justify plug-and-abandonment decisions and quantify the underperformance of problem wells or well components. This information gives a measure of the probability of what can go wrong. It provides a key input into risk assessments – a fundamental process in understanding the potential interruption to production and critical business processes.

Hydrocarbon production is inherently risky. The consequences of well failure to a company’s balance sheet and reputation can be profound and long-lasting. To beat the odds, operators need to have the best possible measure of what the odds are in the first place.

Case study

Globally it is estimated that 30 to 45% of active wells exhibit some form of integrity problem during their life. The primary issue is sustained annulus pressure, signifying a continuous leak path from an active feed source, typically the reservoir. Other common problems concern the failure of safety-critical elements, in addition to widespread issues of corrosion failure of specific well components, including tubing, external casings wellheads and Xmas trees.

Tubing integrity analysis

A major operator installed Wood Group Intetech’s well integrity management software to track annuli pressures, diagnose sustained casing pressure (SCP) and keep the regulator informed of high-risk wells. The evaluation of any contribution of corrosion to the integrity status of the wells was excluded.A specific focus on well integrity data analysis resulted in resolving issues and reducing wells shut in. Year-on-year, the operator introduced more categories of well monitoring data, gradually encompassing well fluid composition monitoring, installed equipment testing results, wellhead movement monitoring and results from tubing and casing caliper.

A decade after the initial software implementation, the field conditions had changed dramatically, with water cut levels rising from negligible to several per cent. Given the presence of acid gases (CO2 and H2S) at significant levels, corrosion of the production tubing was a major risk.Many wells were identified to have annulus gas leaks, resulting in the need for interventions. In some cases, the shutting-in or abandoning of wells led to high Opex, low oil recovery, and unsafe operation.

To address this emerging integrity challenge, the tubing material performance model was enabled. Since corrosion rates are affected by many parameters, a system interface was enabled to provide a real time production data source. The tubular material degradation model takes into account the mass transport of corrosive materials to the surface and the corrosion rate therefore has a flow dependency. There is a significant influence on calculated corrosion rates compared to models that do not take flow effects into account. A sand erosion model was also incorporated and safe operating envelopes for 13 Cr and other alloy tubing were added.

The model output gives, on a per tubing basis, the wall thickness loss of individual well tubulars (Figure 1) and a cross-field review of the installed tubing to identify the percentage of wells with wall thickness loss in various fractions (Figure 2), predicting future workover demand.

Since tubing integrity was a high priority, the software model provided significant value in evaluating the real time aggressiveness of the well fluids. The model output identifies wall thickness loss per tubing and can be used to prioritise the tubing strings to log, ensuring that the logging budget is correctly focused.

The real time evaluation was also used to identify wells with higher day-to-day corrosion rates, which were then prioritised for batch inhibition. Once placed under the batch inhibition programme, wells enter the schedule for re-treatment within the required time-frame to ensure that this critical integrity treatment is maintained.

This case history illustrates that ten years after the original implementation of the well integrity management system, critical integrity challenges arose which were not foreseen at start-up. The benefit of the system was that it was designed to be ‘future-proof’ and the required functionality to address the emerging problem was readily enabled.

Edited from an article by Colin JB Smith

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