SUBSEA PRODUCTION TECHNOLOGY Part III Subsea processing - Can it happen

Phased approaches by industry task forces drawing technology closer to commercial reality The following is Part III of a three-part series surveying operator and supplier/developer opinions on the status of subsea processing. Featured in this segment will be Paulo Pagot, coordinator of subsea separation systems for Petrobras, and Peter Lovie, vice president of engineering for Bardex Subsea Corporation. Featured in Part I were Leofric Studd, senior devel

Phased approaches by industry task forces drawing technology closer to commercial reality

The following is Part III of a three-part series surveying operator and supplier/developer opinions on the status of subsea processing. Featured in this segment will be Paulo Pagot, coordinator of subsea separation systems for Petrobras, and Peter Lovie, vice president of engineering for Bardex Subsea Corporation. Featured in Part I were Leofric Studd, senior development engineer with BP and Johan Harboe, manager of subsea technology with Norsk Hydro. Featured in Part II was John Cotton, product manager with Kvaerner Energy. The views expressed by the interview-ees are their own and do not necessarily represent company positions. This survey was conducted and written by Peter Lovie of Bardex.


Paulo Pagot is Petrobras's coordinator of subsea separation systems in the Procap 2000 program and is located at Petrobras' R & D Center (Cenpes) in Rio de Janeiro. At various times in his 15-year career, he has had responsibilities for platform design, fabrication, and installation.

Well and Seabed Boosting: There are valid practical scenarios for both categories of subsea boosting technologies - those that introduce energy within the wells, and those that introduce energy at the seabed.

Technologies that introduce energy inside the wells are useful for the shorter distances, depending on the pressure loss in multiphase flow. Oil viscosity, emulsion grade, water fraction and other factors affect this pressure loss. Subsea boosting technology may be chosen for the production method appropriate in the oil field (for example, if gas lift is being used, then it makes sense to employ a gas driven subsea boosting system). For the longer distances the subsea boosting system, besides increasing the oil recovery and bringing earlier revenues, also enhances the overall return on investment by allowing use of existing (already paid for) production facilities on platforms that may have surplus processing capacity. The comparison is then between subsea boosting and an additional platform.

Petrobras's interest in Subsea Boosting Systems: In the last 12 months, Petrobras has spent 23,000 staffhours on subsea separation systems (SSS). We have made several conceptual designs for real scenarios in deep water. In one of these scenarios, we compared a conventional field development system using two semisubmersible production vessels versus SSS.

We evaluated four different technological routes on the SSS. It was not an exact comparison because the floating production systems inject water into the reservoir, produce twice as much, and send the production over a longer offset distance. Naturally, it would have been possible to design an SSS to produce at the same rate.

Nevertheless, the comparison is instructive and shows the potentially attractive economics with SSS (Table 1). In another scenario where the median water depth is 1,200 meters and the wells are three to 15 km from the platform, water injection and gas lift were planned. The subsea production system (multiphase pump, separation and electric submersible pump) can increase total recovery by 50%.

We do not expect that subsea boosting systems will be a medicine for all diseases, but do believe that they certainly will have a place in future oil field developments. We must work quickly because the potential places where subsea boosting technologies might be used are currently candidates for conventional and more expensive platforms. The magnitude of expenditure is a few million dollars in the technology development stage, but the return in the production stage will be as high as hundreds of millions of dollars in large oilfields.

Fundamental Issues to Resolve: Critical points in subsea processing are the electrical and control system. The high cycling isolation and control valves are key points too. We have to develop these items and prove their reliability because intervention, maintenance, and repair (IMR) in a real subsea environment can be very expensive. In order to get the best from a subsea boosting system, it is necessary to consider its use from the beginning of the field development and optimize all the field development investments to suit. This makes it clear why we have to prove the endurance of the subsea boosting system before we have confidence to consider its use in a live field development.

A first step may be possible by using a prototype at an existing shallow water platform production system that was conceived without a subsea system, located over a reservoir that has already been largely drained or is close to exhaustion. The investment in this test would be high - something like $10-13 million - and any oil company would like some assurance of recovering that investment during the test. Although in deeper water there may be justification for that added recovery, it still is difficult to show a positive NPV in this kind of scenario.

Alternatively a joint industry project with several oil companies may spread the risk, increase the relative benefits to each participant and be a more probable way to make this happen.

Access to Past Work: The industry publications present papers about pioneering initiatives in subsea boosting systems, but after some time no one talks any further about them. The systems are removed and we never know if they ran properly or not. The experience remains restricted to the companies involved. We hear conflicting stories. Why don't these developments progress? This is a good question to which I am searching for a good answer! People involved in a poor success are a good teacher to all of us.

Plans to Resolve Industry Uncertainties: We'd like to have all of these subsea boosting technologies developed and ready for use. We trust in this direction and are putting money on it. Of course, priorities have to be established, but the three main boosting systems are being pursued (SSS, multiphase pumping and subsea ESP).

For the first time in the world, several weeks ago, Petrobras installed a subsea ESP system. This system is located in the Campos Basin. A Borneman multiphase pump is currently being tested onshore in the northeast of Brazil. We are working to install a gas driven SSS prototype in a live field during 1996.

Combinations: For each weakness of one technology it is possible to build combined methods to overcome it. For example, why not use gas lift or a subsea ESP with a subsea separation system or with multiphase pumping? We have many boundary conditions to be considered in an oil field development: produced fluid properties, environmental conditions, water depth, production methods, etc. The effects of the combination of these conditions indicate the way to the most profitable solution.

Remaining Technical Issues: The reliability of the subsea boosting systems remains critical because of the huge amount of money involved in the field development. It is necessary to test components and prototypes in order to prove the reliability of each of them. We have to believe in these new subsea boosting technologies, join our efforts, and install prototypes in places where the chances of success are maximized, avoiding an attack on all of the difficulties at the beginning.

Bardex Subsea

Peter Lovie is vice president of engineering for Bardex Subsea Corporation in Houston. His responsibilities include engineering and marketing the valved multiported connector, participation in the Deepstar program (multiphase transport and equipment - 200). He previously led development of the GLASS subsea separation and single phase booster for a group of US Gulf operators.

The Dilemma: We are puzzled by oil company actions - participation in a range of R&D projects on subsea processing in recent years, but not applying the results. This hesitation makes difficult to justify continued investment in marketing and system development for subsea processing technologies.

My company is not the only one without orders, even though this technology has been the subject or field prototype trials, several system development projects, and some field application study programs.

Technology Niches: We detect a growing realization among system suppliers and by operators that each subsea processing technology may have a particular application niche.

Our guess is that multiphase pumps may be the way to go for many of the lower gas-oil ratio (GOR) applications, but that for the higher GORs often in such areas as the US Gulf (100-200 cf/b), the power consumption could get to 1-4 mw for 10-20,000 b/d. Separation and single phase pumping at 100-200 kW, for example, may make more economic system sense, particularly when the potential for solving the hydrate issue is taken into account. Looked at the other way, use of a multiphase pump that works well at 100 cf/bbl in a field with 1,000-2,000 cf/bbl may reduce liquids capacity from 8,000 b/d to roughly 1,000 b/d.

Deepstar Input: The multiphase transport technical group in the Deepstar program (multi-operator investigation into economic deepwater production) is making progress in addressing the question of what may work

best for different field conditions. We are shifting from a generalized and theoretical decision tree or general evaluation of the multiphase transport issue to creating a road map of what system may be most appropriate for typical field conditions to guide future system designers.

Different technologies will be tested on paper in the next 1-1/2 years for what might work best for three specific typical field scenarios in the Gulf of Mexico. There is a range of different operators and vendors involved, so the potential exists for a forum for good testing of ideas and debate, getting away from the simplistic multiphase pump versus separation debates of the past.

Duplications: Exxon's work on the SPS in the US during the early 1970s covered much of the ground that the GASP did in the late 1980s in UK for a group of North Sea operators. Similarly, Bardex's GLASS deep water separation and pumping system development in 1990-1992 for four US operators is being largely duplicated in the UK in 1994 for a different group of operators in the DEEPSEP development.

One of the byproducts of Deepstar may be improved communications on what has and has not been developed to make for efficiencies in development expenditures and avoid future duplications.

Market Trends: With better understanding currently of the thinking on the field development options open to operators, it becomes apparent that the estimates for market size for subsea processing systems that many of us made 2-3 years ago were far too optimistic. We've asked in Deepstar and elsewhere for some sense of numbers of specific typical deepwater field requirements of the operators in that group. With that information it would become possible to relate to size of market segments (how many field development prospects might realistically be well suited to multiphase pump systems, separation and boosting systems, and so on).

We might then start to see what future we, as vendors and contractors, may have in responding to realistic market needs - but we have been unable to obtain that information. However, Leofric Studd, Johan Harboe and Paulo Pagot go a long way in the discussion here in defining realistic technical parameters for the use of subsea processing, making a credible market assessment more feasible.

Shift Away from Basic Development: Basic long-term development work of the type achieved by most developers (Table 1 in Part I - December 1994 issue) seems to be getting much more difficult to achieve. We have seen a shift in the last year away from funding developments that may offer big but long-term advantages, to those that have an immediate project or specific near- term payoff.

Risks: In the early development of the GLASS subsea separation and boosting system, we had to wrestle with weighing operational, technology, and economic risks for US Gulf conditions. We found the subjective judgments of well seasoned oil company managers valid and useful, even though the rationale behind them were not always explained. A collection of these judgments was combined in a consensus and assigned quantitative uncertainties to quantify probable risks - essentially the Delphi Method. It became possible to draw attention quantitatively to how significant these risk factors really were. It was very instructive in putting risks into perspective. It was not at all easy or quick to reach a consensus. However, once the basic thinking was sorted out, the details of the analytical tools were not difficult. They include the same packages many operators now use to include probabilities and risks in their economic assessments.

Difficult Times: Current tight budgets and oil company layoffs can mean that the experienced hands that see what can be made to work, and make it happen, are gone. Tight budgets and job insecurity can scare off riskier commitments on new technology or for developments that do not offer specific now-or-next-year project payoffs.

Oil company engineers who could overcome difficulties and make these new technologies work are often frustrated and cynical, and keep their heads down to stay clear of downsizing.

We listen to major contractors who are encouraged by end customers to develop new technologies (and they'd like to), but they can't see a return to justify making that investment. This is not encouraging to smaller equipment vendors who lack the margins of ten years ago to risk investments in developments for the future.

Attitudes on Complexity: An official representing a pioneering US independent oil company said, "Most of the subsea pumping outfits I have seen or read about, with the possible exception of SMUBS, tend to be very complex with all kinds of auxiliary gear. There is a natural reluctance on the part of most engineers to put complex things in places where you cannot get at them or where it is very expensive to accomplish repairs.

"Intuitively, the idea of putting level controllers, lots of actuated valves, lube oil pressure sets, variable speed drives, electronics, switches, and pig launchers in very deep water suggests extremely high operating costs and downtime.

"Simple translates into reliable. That, plus the niche aspects, accounts for much of the reluctance to apply these technologies. Additionally, there are few companies who can afford to conduct experiments or construct prototypes for testing. Everything we find has to be brought on production as quickly and as reliably as possible if we are to have a hope of staying the business."

North Sea experience might give cause to counter such views, but nevertheless they do demonstrate the attitudes that often exist.


  • Many of the smaller North Sea fields that a few years ago had been seen as candidates for subsea processing have turned out be more amenable to development by adaptations of existing technologies. For example, there may be enough of them and they are close enough together to tie more economically in to a central facility, as in BP's ETAPS. In other instances, conventional economical technology such as gas lift and making flow lines larger than usual have also helped this trend. As a result, the prospects for North Sea fields as viable subsea processing candidates are now seen as slim or none, in contrast to the optimistic projections of 2-4 years ago. Exceptions may be in the deeper more remote waters of West of Shetland or elsewhere in the world.

  • Leading operators now view both multiphase pumping and separation/boosting as technically viable techniques, and may now seriously consider them, but they do not yet see many applications.

  • Line blockage issues (hydrates and paraffin) have been highlighted by recent Gulf of Mexico and North Sea problems. Some form of subsea separation may be beneficial primarily to mitigate these problems and reduce corrosion, and secondarily as a solution to the transport problem.

  • Basic technology development has become much more difficult in the last year or two, typified by experiences quoted here.

  • The perception of operators and of many vendors and contractors is now that the market for subsea processing systems of any technology is likely to be much more specialized than was foreseen 3-4 years ago.

  • Although the majority of basic developments on subsea processing have occurred in Europe, the indications here are that Brazil is assuming the world lead in the applying this technology.

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