Future exploitation of oil and gas reserves will depend on the development of difficult fields, so-called because of the technical and economic challenges they pose. This is due to their location, geology or nature of their reserves.
Difficult fields can be categorized into five broad headings: viscous oil, high pressure/high temperature (HP/HT), fluid management problems, remote high GOR Fields and geologically difficult (e.g. thin pay zones). Each field type has specific production problems.
Economic exploitation will depend on the availability of suitably improved process equipment and technology. To quantify these requirements, AEA Technology surveyed the views of oil companies on their perceived needs, priorities and required development time-scales.
In response, AEA Techno-logy formed the Difficult Fields Indystrial Group (DFIG) to coordinate work in the high priority topics identified from the survey. This group provides a forum for discussion between all relevant parties in equipment and technology development: DFIG also undertakes a core work programme that includes studies in agreed topic areas.
The formation of natural gas hydrates during subsea multiphase production can cause substantial operating problems due to partial or complete blockage of pipelines and process equipment. Gas hydrates are ice-like compounds formed by the inclusion of gas molecules (methane, ethane, propane butane, hydrogen, nitrogen and carbon dioxide) in cages of hydrogen-bonded water molecules. Unexpected hydrate formation in pipelines and processing facilities causes expensive and potentially dangerous incidents.
Designing cost-effective injection systems for hydrate control requires consideration of many factors such as pipeline insulation and heating, start-up and shutdown procedures. It is also important that physically realistic and accurate methods are used to calculate hydrate formation conditions and methanol partitioning between phases.
The potential for hydrate formation can be significantly reduced by appropriate system design and specification. Also, an effective hydrate prevention strategy relies on the ability to accurately measure or predict the conditions under which hydrates will form and the influence of process modifications or inhibitor addition.
All possible scenarios which could lead to hydrate formation during the operation of hydrocarbon pipelines and processing facilities should be considered during the design stage. Consistent methods and calculation have been developed to establish the conditions at which hydrates will form and the requirements for hydrate inhibition. These procedures cover warm-up, shutdown and continuous operation of subsea pipelines, hydrate formation conditions, inhibitor requirements and provide advice on best practice.
Use of such procedures early in the design process may reduce costly remedial work at a latter stage. General principles which should be borne in mind include:
- Minimize opportunities for Joule-Thompson cooling.
- Reduce areas where liquid can collect, e.g. dips in pipelines.
- Minimize water content of C2-C5 streams
- Minimize pressure.
Presence of stable emulsions in production systems is usually considered undesirable. For example, in viscous fields the formation of stable oil-in-water emulsions incr-eases the wellstream viscosity and makes the task of achieving separated oil and water qualities difficult.
Considerable effort has focused on ways of resolving oilfield emulsions and so alleviating the problems they cause. Such work is both necessary and technically challenging, but often fails to address important issues such as why emulsions form and how original formation can be limited.
An emulsion is a heterogeneous liquid system comprising two immiscible or partially immiscible liquids where one of the liquids is dispersed as drops in the second. The presence of an emulsifying agent stabilizes the dispersed phase and inhibits drop-coalescence and phase-separation. In this respect, an emulsion is distinct from a simple dispersion where phase-separation occurs readily.
For most oilfield emulsions, the water is finely dispersed as spherical drops in the oil. This is termed a water-in-oil (W/O) emulsion or normal emulsion. Where the oil is dispersed in the water, the emulsion is termed an in-water emulsion (O/W) or reverse emulsion.
To complicate matters further, dispersed phase drops may themselves contain drops of the external phase. These emulsions, termed multi-stage emulsions (e.g. water-in-oil-water emulsions) add appreciably to the problem of phase - separation.
It is generally accepted that emulsions are thermodynamically unstable owing to their high surface free energy, and that, given time, an emulsion will revert to a lower free-energy state (i.e. minimum surface area). Three components are required to form an emulsion: agitation, immiscible liquids and emulsifying agents.
Using current processing techniques it is virtually impossible to exclude produced water, avoid emulsifying agents and suppress agitation. It is difficult therefore to prevent emulsions from forming. However, by partial exclusion it may be possible to limit emulsions.
Formation of emulsions can be limited by reducing levels of produced water, emulsifying agents and agitation. This may be achieved through:
- improved operating practices.
- improved equipment design.
- better equipment selection procedures.
- alternative production methods.
Work has been undertaken to identify the essential process features that contribute to emulsion formation and the associated equipment and operations. Based on this information, ways of limiting emulsions have been explored.
The deep, hot gas condensate prospects of the Central Graben are generally characterized as severely over-pressurized, with possible wellhead flowing pressures of up to 15,000 psi or more. A central part of the design and exploitation of these reservoirs may be the strategy adopted for letting the pressure down to more conventional processing levels of around 1,000 psi.
Clearly in reducing the wellstream by such pressures, a very large amount of energy is lost which could, with the right design strategy, be recovered and used elsewhere. This could involve use of turbo-expanders to generate electricity. Such an approach would have implications for the manner in which the pressure is reduced.
In allowing such large pressure drops, the supercritical dense phase hydrocarbons will flash to a two-phase gas-liquid mixture. At the conditions typical for these wells, the liquid phase may be formed as extremely fine, sub-micron size drops.
This may lead to significant problems with the primary separation system, in that valuable condensate may be lost to the gas side, with attendant problems for gas export lines. A possible approach to this problem may involve looking at the fundamental design of the gas-liquid separation system.
An area of primary importance in the development of these wells for subsea applications is protection of the low pressure downstream equipment against unwanted pressure transients. With the very high pressure differentials encountered, the consequence of a sudden failure of the pressure regulating equipment (production choke) is that the low pressure side will experience a very rapid transient.
To protect against potentially catastrophic over-loading, high integrity pipeline protection systems will be required. There are three key elements in the design and operation of such systems:
- Prediction of the rise in pressure with time so that a system may be designed with maximum confidence
- Specification of a pressure detection and feedback system with sufficiently rapid response
- Specification of a suitably fast-acting valve.
For more information contact Stephen Davies at the Difficult Fields Industrial Group. Tel: (44) 1235-434978 or Fax: (44) 1235-434010.
Copyright 1995 Offshore. All Rights Reserved.