For all the talk of the intelligent oilfield and smart well-based operations, there are still areas of the reservoir where operators can obtain more knowledge about their subsea operations – in particular, activities further downhole and around the wellbore. Emerson/Roxar’s Vincent Vieugue and Terje Baustad explain how.
Wells and reservoirs equipped with downhole sensors to monitor field conditions have been around for many years. Emerson Process Management’s own downhole pressure and temperature gauges have been operating and transmitting data uninterrupted for over 20 years on Statoil’s Gullfaks C production platform in the Norwegian North Sea, for example.
There still remain, however, areas of the reservoir that operators have little information on and where there is a widening recovery gap between topside and subsea wells. Subsea wells, on average, tend to generate average recovery rates of up to 15% less than their topside counterparts.
Why is this? There are, of course, the high costs and risks of subsea intervention with the capabilities of subsea monitoring, wellbore equipment and control systems severely tested the deeper the waters become and where the costs of intervention are often prohibitive.
There is also the focus on geological models and the seismic information derived from the reservoir – sometimes at the expense of real-time production data from the well.
Finally, there is the simple reason that some parts of the reservoir and the well remain inaccessible to many operators today. In such circumstances, operators are ‘flying blind’ so to speak and are all too often unable to answer the key question: why is this well not performing as successfully as neighbouring ones and what can be done to improve it?
Permanent, real-time monitoring of the production wellbore and nearby downhole processes and infrastructure has never been more important in offshore reservoir operations today. This is particularly the case in both older and new discoveries in the North Sea.
In the older, brownfield North Sea sites, for example, where seismic has been shot previously in great detail, where the field is tied into existing infrastructure and where there is a complex set of interdependencies between ageing and new technologies, the difference between meeting production targets and fields becoming economically viable is often to be found in the quality of information generated downhole.
In the newer discoveries, such has been the increased focus on fast tracking developments from discovery to production that real-time information on well and reservoir performance from the outset is crucial.
Fast-track examples include Statoil’s Krafla Oil and Visund South oil & gas fields and Total’s Atla gas and condensate field, the latter only being discovered in October 2010 and due to start-up in October 2012.
So how are technologies rising to this challenge? Here are two examples relating to measuring multiphase flow measurements downhole in the well and the all-important issue of well integrity.
Measuring flow rates downhole
While multiphase meters have become an established element of many offshore fields for over two decades, enabling operators to avoid costly test separators and test lines, they have rarely been able to generate accurate multiphase measurements and reservoir flow from downhole in the well or from different well zones. The rise in multilateral, multizone wells and intelligent completions in the North Sea has only exacerbated this challenge, where multilateral wells are a means of increasing reservoir exposure while at the same time reducing capital and operating costs, with Statoil’s Glitne and Sleipner being two such examples.
The increased use of extended reach wells with multiple production targets as well as multilaterals with several branches has increased the need to pinpoint not only production data from each wellhead but from each producing zone along the wellpath. To date, however, multiphase meters have only been able to provide data on total production flow from all their wells rather than flow from specific well zones.
Against this backdrop, Emerson has developed a new system which generates multiphase flow measurements from downhole in the well. The new system, which is based on its multiphase metering technology, provides multiphase measurements of fractions and flow rates from either single bore or multilateral well configurations. In this way, gas fraction and flow velocity can become as accepted a technology in permanent downhole applications as temperature and pressure already are.
The 3.5in tool and 1/4in cable is compact and easy to install, fitting in both short zones between packers and in 7in liner/ casing. There is a single conductor for all tools including the downhole gauge and the system can be fitted to existing subsea control systems without the need for modifications. Measurements are performed in the tubing through nonintrusive sensors.
The system is based on a new measurement principle which allows for capacitance and conductivity measurements in separate sectors, in addition to the full cross-sectional area. This results in more combinations and more accurate fraction measurements. Furthermore, rather than systems only being able to perform cross-sectional measurements, the meter can perform both rotational near wall measurements and cross-volume measurements, thereby providing a comprehensive mapping of flow regimes.
The new system is able to handle all types of flow regimes varying from horizontal laminar flow to full developed vertical annular flow and is also backed up by a new field electronics system, which allows for capacitance and conductance measurements to be combined in one unit.
The flow sensor system also includes a new water cut measurement tool based on dual velocity measurements and a density sensor, measuring the density of the fluid using gamma rays. It can operate at pressures and temperatures of up to 10,000psi and 150°C respectively – well above the required rates of most downhole wells.
For operators, the system opens a new window into subsea production, generating data previously unavailable. It allows operators to control multiple production wells, measure the individual flow zones of oil, gas and water, establish optimum flow rate control if there is undesirable water or gas encroachment in a particular well zone, and determine which branches of multilateral wells are producing which fluids.
If a water breakthrough occurs, for example – something which can have a devastating effect on production flow, particularly in gas injection wells so prevalent in the North Sea – only a branch of the well needs to be closed down rather than the complete well.
For multiple zone wells, the effective measurement of downhole composition and flow measurements will allow for optimum control of each individual zone, providing early warnings of transient behaviour, such as slugs, and enabling topside processing to be adjusted to preempt such events.
Generating information
In addition to measuring flow downhole in different well zones, one of the most inaccessible areas in subsea well production systems today is the annulus of an oil well – the space within the well where fluid can flow.
In a completed well, there are normally at least two annuli: annulus (A), the space between the production tubing and the smallest casing string with annulus (B) located between different casing strings.
With onshore wells, operators tend to have easy access to annulus (B) via valves at the wellhead, ensuring that pressure can be regularly checked and if necessary adjusted. This is not the case in subsea wells, however, where there is often no access to the annulus (B) following the landing of the casing hanger and sealing and cementing of the casing.
A build up in pressure behind the well casing in subsea production wells can have significant repercussions for well integrity. It can cause the cement sealing to deteriorate leading to a loss of casing integrity and can result in the vertical migration of oil and gas towards the surface, creating a potentially hazardous situation and a genuine threat to offshore safety.
In some cases, it may even lead to the shutting down of production – a decision often made because operators simply don’t have enough downhole information and are erring on the side of caution.
Without access to such pressure data, operators sometimes have to resort to excessive and expensive overdimensioning of casings to compensate for worst case scenarios. Several oilfield services companies have previously written about these difficulties particularly in HP/HT areas of the North Sea, the Elgin/Franklin fields on the UKCS being one such example.
To combat this information gap on subsea production, Emerson has developed a new wireless instrument that generates real-time pressure and temperature information from the annullus (B) within the well casing.
The new wireless instrument attaches to the same cable as other reservoir monitoring gauges and detects any variations in pressure behind the casing string. In this way, it can provide early warnings of high pressures and allow intervention or other remedial actions to be planned and implemented in a timely manner. It will also provide an important tool to government regulatory agencies overseeing safety and environmental protection.
As new oil becomes harder to find, fields become ever more geologically complex, and with an increased focus on increasing recovery rates in existing fields, establishing greater control and generating more information from subsea production operations is likely to be one of the most important areas for future technological innovation.
Bringing greater intelligence to downhole operations is likely to be a key part of this. OE
About the Authors:
Vincent Vieugue is VP sales & marketing in the Roxar Flow Measurement division of Emerson Process Management. He previously served with WesternGeco as account manager for Hydro, Shell, ExxonMobil and ChevronTexaco in Norway.
Terje Baustad is product manager, downhole at Roxar Flow Measurement. He presented a paper at OTC 2011 in Houston entitled: ‘The development of an instrument measuring pressure behind the casing in subsea production or injection wells
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