The role of subsea sampling in securing maximum effectiveness from multiphase meters is reviewed here by Mirmorax chief executive Eivind Gransaether. He discusses how subsea sampling is addressing other crucial production management issues offshore, such as injection water, water breakthrough, chemical analysis and EOR, and the major impact it is having on today’s field economics.
With test lines for subsea well testing costing as much as $60 million and the accompanying logistical challenges involved, the installation of permanent subsea multiphase meters, as an alternative to well testing and as a means of increasing recovery, has become a priority for many operators today.
The figures also bear this out: Gioia Falcone from Texas A&M University and Bob Harrison of Soluzioni Idrocarburi estimate that, as of 2010, over 3300 multiphase meters were installed worldwide.
Yet, the focus on multiphase meters – however important – overlooks the crucial role of subsea multiphase sampling in offshore fields today. Multiphase meters can only be truly effective and accurate if they are precisely calibrated and are subject to high quality, volumetric sampling and reliable reservoir simulations over the field’s lifetime.
For all their current effectiveness, multiphase meters face a number of offshore challenges today. These include the wide range of conditions and fluctuating flow rates in many offshore fields. Many wet gas fields, for example, produce over a wider range of process conditions than previously with an increased amount of liquid and water in the gas flow.
In addition, remote field locations, growing water cuts and fast changing reservoir and well characteristics are becoming increasingly common in reservoirs today, putting more pressure on multiphase meters.
The last few years have also seen a growth in subsea tiebacks and longer horizontal production pipelines, as operators look to tie in smaller fields to existing infrastructure and better manage costs. This growth has exacerbated the importance of real-time, subsea monitoring of the transferred fluids for both flow assurance and production allocation purposes.
With longer tiebacks and potential delays to detecting water breakthrough, for example, the need to track threats to pipeline and production integrity and accurately measure production and fiscal allocation is crucial.
Under such circumstances, metering systems today are facing huge pressure to accurately track multiphase and wet gas flows and overcome any potential threats to accuracy, such as changes in oil characteristics and varied flow conditions outside their calibration ranges. This is where subsea sampling comes in.
Subsea sampling and processing can play a key role in generating the fractional data on oil, gas, water, salinity, PvT (Pressure, Volume, and Temperature) and other information that today’s multiphase meters need to be calibrated for. In that way, such meters can operate to maximum effectiveness.
Despite their clear importance however, many subsea sampling systems have been relatively crude in the past, failing to generate a truly volumetric representative sample that contains fluids from all the phases.
Such sampling techniques include the hot stab method, used to move fluid from one device to another; extraction by differential pressure; or flowing the well to a surface test facility that then captures samples.
The weaknesses of these techniquesare that they are used just topside and are manually-driven; samples are taken randomly without taking note of the flow dynamics of the fluids being sampled; and the original conditions in the field, such as pressures, are overlooked. The result is an incomplete sample with the differential pressures used to sample and then transport the samples a main source of inaccuracy. So how can we address these limitations?
In designing a new subsea sampling system, a key criterion was that it must be deployed subsea close to the wellhead, where more accurate fluid properties can be generated and where multiphase meters are deployed.
What was also vital was to maintain the sample at its original pressure conditon from extraction to delivery to the surface and then transportation to the laboratory facility. Maintaining the pressure condition and the true representation of the process is crucial in providing accurate PVT analyses.
This has been achieved through an ROV-based subsea sampling system with a number of key elements. Via the ROV, the subsea sampling system extracts and transports samples into sampling bottles under isobaric conditions and then transports them to the surface. This is achieved through an ROV-operated docking sampling unit (DSU), consisting of a docking unit, a hydraulic sample extraction system and sampling bottles.
The ROV transports the sampling device from the surface vessel and docks onto a stationary subsea sampling interface (SSI) through a standard hydraulics and manipulator system. The two parts are then connected with a robust connector and barriers which are then tested to verify pressure integrity.Figure 1 illustrates the system in sampling mode, after the DSU has been docked onto the SSI.
This operation is then repeated multiple times on the same well in order to secure a set number of samples over a certain time period. The result is a sampling system subsea and close to the wellhead and a seamless process from sample collection to final analysis topside.
It has already been stressed how accurate subsea sampling can play a key role in effectively calibrating multiphase meters. This is particularly the case as fields age with the uncertainty of metering systems tending to grow over time (see Figure 2) and confidence in real-time production data diminishing as field conditions change and the verification of input data becomes more cumbersome to obtain.
In such circumstances, effective volumetric subsea sampling can play a key role in sustaining production and having a positive effect on the bottom line and financial returns from the field.
Aside from multiphase meters, effective subsea sampling can also add value to other areas of offshore production management today, helping to provide enhanced returns.
Take, for example, chemical analysis. With operators facing increased threats to flow assurance from hydrates, the injection of chemical inhibitors, such as methanol and ethylene glycol (MEG) and low dose hydrate inhibitors (LDHIs), is particularly popular today. Such inhibitors are playing a key role in combating scaling and corrosion, with chemicals often used to break up surface tension and facilitate the oil and gas flow.
At the same time, however, operators also need to establish greater control over the measuring and injection of hydrate inhibitors to ensure the correct inhibitor amounts are injected and that injection rates are changed when conditions change.
For thermodynamic inhibitors, such as MEG, which tend to require higher injection rates and concentrations, injection rates must be adjusted if operating parameters, such as high sub cooling or high water cuts, vary.
Having information on how these chemicals propagate from an injection well into other wells will provide operators with a better understanding of their reservoirs, enable them to optimize their chemical injection programs, and ensure better economics for the reservoir.
Effective subsea sampling is able to achieve this, generating accurate volumetric samples that can then be subjected to chemical analysis and help determine future chemical injection programs. With EOR-based chemical injection programmes, subsea sampling can track the flow of injection fluid into the well, measure its effects, and provide an accurate sample where chemical content can be extracted.
The rise of produced water re-injection (PWRI) programmes has also led to a growing need for detailed information on the size and amount of sand and oil in produced water – whether it is reinjection, discharged or processed. Again subsea sampling can play an important role in monitoring the reinjection process, generating greater detail on the specific components of produced water, and optimizing enhanced oil recovery programmes.
So what effect is subsea sampling having on the economics of reservoir management? Let’s take a look at how it supports multiphase meters as an alternative to well testing. While, it’s difficult to utilize specific numbers, it’s clear that the costs of well test lines can have a highly negative effect on the economics of a reservoir.
For example, subsea well intervention can be a labour-intensive and costly activity with rig costs running at up to $1 million a day. Aligned to this is the lost production as a result of the shutdown and the testing and reconnection of the well. For a well producing say 15,000b/d of oil, where the crude will be sold for around $95 a barrel, and where the well will lose production for 12 hours, the lost revenue is already over $700,000.
Furthermore, while the use of multiphase meters to generate real-time data, can pre-empt these costs, if these meters are inaccurate and unable to adapt to changing flow conditions, the impact on flow assurance and field economics is likely to be significant.
Alternatively, for a development that can enjoy the benefits of fixed data points for later reservoir simulation and effective multiphase subsea sampling, the cost savings and positive impact on flow assurance are likely to be substantial.
Whether it is multiphase meter calibration, enhanced oil recovery, chemical injection or subsea tiebacks, it’s crucial for today’s operators to have effective subsea sampling and monitoring capabilities in place.
Encouragingly, it now seems that the technologies are now rising to this challenge and delivering significant financial benefits to the reservoir. OE
Eivind Gransaether is CEO of Mirmorax, the company he founded in 2009. He previously served as subsea engineering manager at Norway’s Roxar (now part of the Emerson group). While with Roxar, he was development manager for that company’s Subsea Retrievable Multiphase meter (SRC) and was also responsible for three other product developments.