Oil Review Africa (March 2011)

March Subsea Systems – Oil Review Africa


                                    BY EIVIND GRANSAETHER, MIRMORAX

The Growth of Deepwater Fields

There’s no doubt that offshore exploration in Africa continues to be one of the industry’s true growth areas. Along with the Gulf of Mexico and offshore Brazil, Africa will account for 85% of global deepwater expenditure between now and the end of 2012, according to analysts, Douglas-Westwood, with annual expenditures worldwide likely to reach over US $24.6 billion by 2012.

Douglas-Westwood also estimates that overall capital expenditure for the period 2008-2012 is expected to total $38.2 billion, 47% of which will be accounted for by Africa. As of 17th January 2011, the World Oil Deepwater Report also found that there were 26 deepwater prospects where drilling activity was underway offshore West Africa.

And it’s not just offshore West Africa which is the focus of activities. In August 2010, the first deepwater oil was discovered offshore East Africa in Mozambique’s Rovuma Basin.

Yet, just as offshore expenditure continues to grow, so do the challenges in ensuring maximum production rates from the reservoir to the refinery once the fields come on stream.

One area of subsea production, that doesn’t gain the same attention as production trees, wellheads, and jumper equipment, for example, is that of subsea sampling.

Subsea sampling today provides crucial input to a key element of flow assurance on many of Africa’s offshore fields – multiphase and wet gas meters.

Such meters provide important real-time information on flow conditions in the reservoir. They can be used to determine maximum oil production and gas handling capacity and can provide early warning signs if there is water breakthrough, for example. Today, many of Africa’s most high profile fields have multiphase meters installed including Total’s Pazflor and Akpo’s fields; ExxonMobil’s Marimba and Kizomba C fields; and ENI’s Mondo field.

Furthermore, with increasingly challenging ownership structures in many of these offshore fields with complex commingled streams and royalty allocations, multiphase meters today are also playing an important role in production and fiscal allocation.

So what is the link with subsea sampling?

It is accurate subsea sampling that leads to the precise calibration, accuracy over time, and effectiveness of these metering systems. It also support these meter’s roles in areas, such as reservoir simulation and field economics, system integrity, the allocation of revenue from tied in fields, and production optimization.

By adding a subsea process sampling system, for example, operators can generate fractional data on oil, gas, water, salinity, PvT (Pressure, Volume, and Temperature) and other information that the meters need to be calibrated for.

And accuracy over time is probably the most important element subsea sampling can provide to multiphase meters today. It is subsea sampling and the calibration of meters that can ensure that a meter installed on a well at the start-up of production is providing accurate estimates of oil, gas and water ten years later – even when the produced fluids in the field have changed.

Yet are today’s subsea sampling systems meeting the requirements of today’s multiphase meters?

Unfortunately, the answer, in many cases, seems to be no.

The US Department of Energy said as much in 2006 when they established the Research Partnership to Secure Energy for America (RPSEA) with one of the key goals being ‘the development and standardization of deepwater sampling’.

There are a number of subsea sampling techniques on the market today, the most popular being the hot stab method and others including the extraction of the samples by differential pressure, or flowing the well to a surface test facility that captures samples.

All these techniques, however, share a number of limitations. Firstly, the techniques are often used topside; samples are often taken randomly without due consideration to the flow dynamics of the fluids being sampled; and the original pressure conditions are not maintained during the fluid sample’s journey to the laboratory.

The result is that there is little way of achieving a volumetric representative sample or being assured that the sample contains fluids from all the phases. The result is low quality samples, no volumetric representation, and low repeatability.

It’s clear that multiphase meters play a crucial role in flow assurance today. It’s up to subsea sampling methods to ensure that they perform to their very optimum ability. Subsea sampling, that can deliver true volumetric sampling on oil, gas and water in the well without interrupting production, can enable the operator to accurately capture fluid properties throughout the lifetime of the field, conduct comprehensive PVT and chemical analysis, calibrate multiphase and wet gas meters, and increase oil & gas recovery from the reservoir.

It was against this backdrop that we have developed a subsea sampling system that overcomes many of the limitations above.

There were a number of key criteria to the system we developed – going subsea and being ROV-operated, a seamless process from collection to analysis; no interruption to production, and being robust.

Firstly, the system needed to be installed subsea. It’s only through sampling at or near the wellhead that samples that are representative of the fluid flowing through the meter can be generated. Another driver for this is the limitation of platform space on many African platforms as well as the increase in subsea tiebacks, with the Pazflor field being one such example.

Having made this decision, the next logical step was to design an ROV-operated system taking the recommendations from the RPSEA partnership described earlier in the article.  As well as recognizing that deepwater measurement is a critical need in the development of reserves, RPSEA also set a goal of installing measurement systems on deepwater wells via ROV.

The system we developed also needed to represent a seamless process from sample collection to final analysis topside – from extracting a representative sample, taking to the surface and then storing and transporting to the laboratory facility. It was the differential pressures used to transport the samples which were the main source of inaccuracy with previous sampling techniques.

The final criteria two were that we did not interrupt production, potentially costing the operator hundreds of thousands of dollars, and we wanted to ensure that the system was robust and able to operate in the challenging and HP/HT environments of offshore Africa.

The solution, that we developed, is therefore built around an ROV operated docking sampling unit (DSU), consisting of a docking unit, a hydraulic sample extraction system and sampling bottles.

The ROV tool then extracts and transports the sample or samples into sampling bottles under isobaric conditions and then transports the samples to the surface. The sampling unit consists  of a hydraulic actuator, collet connector and system for testing sealing integrity.

The second main element is a stationary subsea sampling interface (SSI). The ROV transports the sampling device from the surface vessel and docks onto the stationary SSI through a standard hydraulics and manipulator system. Figure 1 illustrates the system in sampling mode, after the DSU has been docked onto the SSI


Sampling mode systems

Figure 1

The operation then takes place a number of times on the same well with the operator able to obtain multiple sample points on one single ROV operation in order to obtain a fully representative sample over a set time period and to provide the accumulated volume needed to perform analysis topside. And all these samples can be taken without interrupting production.

Another key challenges for offshore operations in Africa is the high pressures and high temperatures in the deepwater fields. For example, ENI’s deepest well in West Africa – the Oberon 2, off the coast of Angola  – contains pressures of up to 10,800 PSI and temperatures of 157 °C.

To meet these challenges, the new system can operate comfortably with HP/HT applications of up to 1000 bar/15,000 PSI and 180 °C / 350°F and has design depth of 3,500 meters.

Testing has also shown the system to be in compliance with design codes even when it is tested at up to 22,500 PSI. The new system is currently undergoing qualification testing.

It’s clear that subsea sampling in Africa’s offshore fields is going to become more and more important over the next few years in guaranteeing flow assurance and accurate production allocation. It’s encouraging to see that some of the limitations of the past are now being overcome and that subsea sampling can take its rightful place as a key element of subsea production systems.