The offshore industry has now reached a stage where there are emerging areas of flow assurance technologies that could hold the key to significantly enhancing the cost effectiveness and productivity of future oil and gas fields.

But which of these potential solutions emerging over the horizon or in early applications are of most interest to the upstream industry’s necessarily conservative operating companies as they tackle new developments in both shallow and deep waters?

A recent paper by FMC Technologies’ Phaneendra Kondapi and Randi Moe compiled a top 30 list of flow assurance technologies assessed by maturity level – embryonic, emerging, matured, or aging – as well as considerations such as effectiveness, applicability, and solution type.

The findings were presented at the 2013 Offshore Technology Conference (OTC) in Houston, with the solutions further categorized into thermal, chemical, hardware, operating, and software sections.

Maturity levels

The four maturity levels need little clarification, with “embryonic” essentially covering technologies still in the experimental or qualification stage, while “emerging” technologies are those growing but still being developed and going through qualification testing. “Mature” technologies mean exactly that, with most considered standard for the majority of field applications but with some wiggle room still remaining for further incremental enhancements. “Aging” technologies, last but not least, are those on their way out due to their inherent limitations, replacement by newer and better solutions, and other considerations such as stricter environmental regulations.

Most of today’s chemical and operating technologies are fairly established and at a mature level, with some further room for incremental improvement. Some of the thermal solutions also are mature (such as thermal insulation and direct electrical heating), but these still have room for improvement for deeper water depths, long subsea tie-back applications, and other challenges.

From a future perspective the most interesting aspects relate to the key technology areas highlighted by Kondapi and Moe as being either at the embryonic or emerging stage: cold flow, subsea coolers, subsea compression, and subsea separation.

Cold flow and subsea compression technologies have not yet been applied on any field but are in the process of being developed for qualification. Statoil’s Asgard field, for example, is flagged as the first expected subsea compression application when it is completed in 2015 (see E&P’s August 2012 issue for a full description of that project’s progress).

Cold flow technology

For cold flow technology, according to the authors, the development target is essentially to implement it in a large-scale pilot testing facility and validate the technical challenges. These include:

  • Long-distance transport of high-fluid-viscosity slurry with high pressure drops and boosting capacity; and
  • High heat capacity because of more hydrate formation, with high water cuts and more crystallization heat.

Cold flow technology has been studied conceptually for a number of years, but it is only relatively recently that initiatives have gotten under way subjecting it to extensive testing in laboratory programs. One such project has entered a demonstration phase, with the goal to bring qualification of the technology to a position where it can be applied in the field. Another cold flow concept that is part of a joint industry project is still being tried out in a laboratory flow loop capable of simulating pipeline conditions.

According to the paper, companies are looking in particular at combining the technology with other subsea solutions such as separation and boosting. The reasons why companies want to progress cold flow know-how become more obvious when the predicted economic and technological advantages are outlined:

  • Reduced capex and opex on heating system hardware and operation;
  • Reduced capex on pipeline insulation;
  • Reduced capex on pipeline vs. dual round trip pigging;
  • Reduced opex on production chemical costs by reducing the need for chemical injection;
  • Reduced opex by reducing monoethylene glycol regeneration needs;
  • Enabling technology for ultra-long tie-backs;
  • Reduced handling of bulk and harmful specialty chemicals;
  • Increased capex and opex for topside processing facilities to process hydrate and wax slurries; and
  • Higher anticipated costs for subsea cooling systems and multiphase/liquid pumps.

Subsea coolers

The other highlighted embryonic solution is subsea cooler technology, which the authors said was gaining increasing attention primarily due to the cost benefits that would be realized by reducing or controlling temperatures. The simplest and most matured cooling device would be a long uninsulated flowline, of course, but more efficient multipipe cooler units have been developed and qualified for subsea use. “A multipipe solution has been used subsea in Australia on the Kipper field and is a required unit for the ongoing development of subsea compression,” they stated.

Like cold flow, subsea cooler advances would have a positive impact on E&P projects, especially for the increasing number of high-temperature applications. The main benefit is an obvious one, with the reduced temperatures allowing for less exotic materials to be used for downstream pipelines and risers, helping to reduce development costs.

Subsea cooler technology also would enable the tie-in of high-temperature fields into existing lower design temperature flowlines to fully use existing infrastructure. Eliminating condensibles from a gas stream through cooling and separation, meanwhile, could simplify the design of the gas-receiving facilities by mitigating or eliminating slugs.

New technologies such as electrically heated pipe-in-pipe are evolving to control flow assurance issues generated by heavy oil fields and long-distance tie-back requirements. The electrically heated pipe-in-pipe solution is still at the embryonic stage, with Total’s Islay field being the first actual field application.

Subsea separation tops list

It is the emerging front of subsea separation, however, that is highlighted as the list-topping “most targeted technology” for rapid development and application. This is due, Kondapi and Moe said, to its huge potential for cost savings by moving some of the traditional topsides fluid processing activities to the seabed.

According to the authors, for maturing fields subsea processing can contribute to increased earnings, production, and recovery, which can improve and prolong the use of existing infrastructure. For new field developments, it can enable cost-efficient and environmentally friendly platformless solutions, where the field is tied back to an existing offshore facility or directly to shore.

Other beneficial impacts include accelerated or increased recovery being achieved by reducing back-pressure on wells; improved flow assurance through less hydrates, wax, slugging, and erosion, with less chemical injection; and the ability to produce in harsher environments. But the obstacles that lie ahead for subsea separation are still substantial. According to Kondapi and Moe, those future challenges include:

  • Achieving liquid-liquid separation and gas-liquid separation from heavy oils;
  • Realizing the optimum combination of pump acceptance criteria with respect to gas-liquid separator design for heavy oil applications;
  • Cost and installation challenges and opportunities to reduce bulky and heavy equipment;
  • Disposal of the separated water; and
  • Improving and maturing an efficient compact design.

Subsea separation technology is by no means brand new – witness the first pilot separation system on the Troll field offshore Norway installed in 1999 (liquid-liquid separation) and 2001 (gas-liquid separation).

But other more recent high-profile deepwater projects such as Total’s Pazflor, Shell’s Perdido and BC-10/Parque das Conchas (gas-liquid separation), and Petrobras’ Marlim (water separation) fields have now seen subsea separation technology successfully applied on a significantly grander scale. As a result, more companies are now increasingly moving toward using this technology to increase hydrocarbon recovery on the development of fields in more challenging and deeper subsea fields.

Editor’s Note: This article has been written with the use of sources including OTC Paper 24250.