Mature fields

Pseudo Dry-Gas Technology Proves Feasible and Valuable for Ultralong Subsea Gas Condensate Tiebacks

This case study describes how gas condensates within a subsea tieback system behave very differently to condensed water from a wet-gas system and therefore a pseudo dry-gas system needs to be configured differently for gas-condensate developments.


Pseudo dry-gas (PDG) technology has been demonstrated successfully for transporting wet gas in a 200-km subsea tieback pipeline in deep water under wet-gas conditions (water-saturated gas). The technology helps reduce the inlet pressure by reducing the liquid content and, therefore, the gravitational pressure drop. The mitigation of the gravitational pressure drop allows the use of larger pipelines to minimize frictional pressure drop, which in turn increases reserves recovery and allows tieback distances to be enhanced.

This paper investigates a pseudo dry-gas system for an ultralong deepwater gas condensate development, building upon research and development already conducted with Strathclyde University. This work was undertaken using nonstandard flow assurance methodologies and simulations, recycling data and results with the advanced computational fluid dynamics simulations of the liquid-removal units’ behavior.

Introduction and Background

Successfully transporting wet gas over long distances must overcome numerous issues, including high back pressure and slugging based on standard gas transportation systems. These issues historically limited the length of tiebacks to 110 km for a single pipeline and 150 km for dual pipelines. The two primary options for gas tiebacks longer than 150 km are currently subsea wet-gas compression, or floating processing and separation vessels with dry-gas export.  

The first subsea wet gas compressor was installed in 2015 on the Gullfaks field, and claims were that it increased gas recovery by 20%. A previous study showed that recovery using a floating vessel was less and it was far more expensive.

The PDG technology described in the paper aims to dramatically improve the efficiency of gas transportation using the natural gas reservoir pressure by minimizing the gravitational and frictional pressure loss for long-distance tieback pipelines. It also holds the potential to address two other concerns of gas producers: CO2 emissions, and maintenance and inspection.

A previous paper, OTC 28949, focused on the use of PDG technology on a biogenic gas development (gas and water) and the operational benefits on the 200-km gas transportation compared to the other available technologies. This paper focuses on the technology for use with gas, condensate, and water, and how this changes the makeup of the system; the dynamic impact on the system for turndown, rampup, shutdown, and restart; and a detailed evaluation of the operation of the liquid system, including the required pumping technology.

The paper describes how gas condensates within a subsea tieback system behave very differently from condensed water from a wet-gas system and why, as a result, a pseudo dry-gas system needs to be configured differently for gas condensate developments. These differences include how and where the liquid drops out of the gas phase, where and if the free liquid is reabsorbed back into the gas stream, and how the bubblepoint of condensate is equal to or very close to liquid-removal units’ operating pressure. This greatly impacts the liquid-handling system compared to a wet-gas (water) design. Therefore, to ensure controlled liquid-only transportation, careful examination of the liquid-removal units’ performance, the liquid-pump selection criteria, and optimization of the system need to be undertaken. This results in a tradeoff between maximum reserves recovery and system complexity.

The paper demonstrates that the liquid-condensate system will remain as a single liquid-phase pipeline, where the number of pumps can be reduced and the pump power requirements are very low and within the existing technically qualified subsea pumps.

The typical system architecture of a PDG network consists of a gas and a liquid network linked at the PDG liquid-removal units (Fig. 1). The liquid network also requires pumps which can be located at the PDG liquid removal units’ skid pump and on the main transport line pumps for boosting to the necessary pressure to reach the liquid disposal location or processing facilities, generally onshore.

Fig. 1—Typical field layout with PDG system.

These liquid-removal units help reduce the inlet pressure by reducing the liquid content and allowing the use of larger pipelines. Several case studies have been performed with PDG technology, including offshore Western Africa, Western Australia, and North of Shetland Islands UK, generally maintaining trunkline inlet pressures around 100 barg at start of field life (arrival pressure 60–70 barg) and 50 barg at end of field life (arrival pressure 30 barg). It also allows the system to operate at very low turndown rates, resulting in increasing the tail-end production. It should be noted that maximum gas flow rates considered for these studies were between 380 to 950 MMscf/D for trunkline sizes mostly in the range of 30- to 36-in. and 24 in. for an ultradeep case with a pressure-reduction range of 60 to 120 bar over a standard tieback.

The complete paper demonstrated that PDG technology for biogenic gas with liquid phase of water could potentially improve reserves recovery for 200-km tieback pipelines to 20% to 40% more than current development inclusive wet-gas compression. Because the behavior of retrograde gas condensate fluid is different than biogenic gas with water, a retrograde gas condensate fluid was used to evaluate the effect of hydrocarbon liquid condensation in the system.

Case Study

A case study was selected with maximum flow rate of 500 MMscf/D, trunkline length of 200 km, and water depth of 1640 m. The paper presents the description of dynamic simulation that was performed to determine how long it takes to build up steady-state liquid holdup at 250 and 125MMscf/D. The liquid removal from the gas system during shutdown was also investigated in the dynamic simulation.

To determine the liquid-handling capacity of the PDG, an extreme event of shutting down the pipeline following 8 months operation at a flow rate of 125 MMscf/D was evaluated. The liquid pumps were used to drain the liquid holdup inside the trunkline. Approximately 75% of liquid holdup was removed during the shutdown in less than 2 days. This demonstrated that, for operating at low flow rates for more than 8 months, the liquid from the gas system can be drained in less than 2 days, reducing the operating pressure and enabling the cycle to repeat. This procedure could be used at the end of the field life to recover more of tail-end gas until the wells are loaded with the liquids.

The liquid, which is removed from gas pipeline by liquid-removal units, will be transported to onshore via a liquid system network which comprises an 8-in. pipeline, four liquid-removal unit pumps, and one main booster pump. After initial evaluation and conversations with vendors, main criteria for liquid network and pump sizing were proposed. The design criteria are presented in the paper.

The authors also discuss liquid outlet flow rate of liquid-removal units for different flow cases, minimum arrival pressure for the liquid system, the liquid-system configuration, and pumps requirements.


  • PDG technology can be used for long (200 km) tieback pipeline, and the trunkline inlet pressure at maximum flow rate at early life is 102 bar compared to 168 bar for single line or dual line. This reduction in pressure increases field recovery. Preliminary results show that the PDG technology can increase recovery 40% more than standard method and 20% more than wet-gas compression.

  • Initial capital cost of dual pipeline and PDG are approximately the same, and because liquid-handling issues make a single pipeline nonfeasible for long deepwater tiebacks, any subsea compression option will only add significant capital cost to the dual-pipeline option. Additionally, the cost reduction of the pipelines will be an order of magnitude less than the additional cost of floating production system.

  • The PDG system uses all field-proven power and pump systems, with no additional qualifications needed. Power requirements are significantly lower than a compression system.

  • Lower power requirements and increased recovery result in 60% reduction of CO2 emissions compared to subsea gas compression.

  • The trunkline can be shut down, drained in less than 2 days, and restarted if longer operation at low flow rate is required. The gas system can be operated for several weeks without the liquid system before pressure and liquid build up in the system.

  • The restart operation after draining the liquid has shown that the liquid surge volume arriving onshore is negligible and the system is not limited to liquid flooding in the onshore. This increases system flexibility. Restart time is determined by maximum drawdown rate per well.

  • Variable-speed drive PDG system pumps can control the flow rate from the system, and the main pump increases the pressure based on the flow rate, meaning that the vendor-recommended pumps are suitable for the liquid system based on all components inclusive of power system being at a field-proven readiness level. 

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper OTC 29332, “Ultralong Subsea Gas-Condensate Tieback—Pseudo Dry-Gas—Liquid-Handling System,” by Lee Thomas, Terry Wood, Afshin Pak, Laura Liebana, David McLaurin, and Stephen Stokes, Intecsea, prepared for the 2019 Offshore Technology Conference held in Houston, 6–9 May. The paper has not been peer reviewed.