EnSys Yocum
Providing Software and Services for Oil Field Performance Improvement

Phone: (781) 274-8454 | Email: info@ensysyocum.net | Downstream contact: martin@tallett.co

Oil Field Insights

Simulation of Subsea Facilities and Riser Systems

EnSys Yocum has applied their software and technology employing advanced calculations to implement innovative solutions for alleviating production constraints and maximizing oil production in several subsea oil fields.  Accurate simulation and de-bottlenecking of subsea flow systems is becoming progressively more important as subsea projects involve greater depths and are increasingly susceptible to potential flow constraints related to slug flow, lower temperature conditions, emulsion formation and subsea/surface separator performance. Our software incorporates an accurate and detailed representation of the fluid physical properties within each flow increment as a function of pressure and temperature. This is necessary to perform the analyses described below which achieved significant improvements in field performance.

Riser/offshore platform in the North Safaniya Field, Saudi Arabia

Field Background:  An example of EnSys Yocum’s innovative solutions employed to prevent subsea slugging involves a network system of 12 subsea wells which flowed into a 24 inch trunkline system and entered a 90 foot, 24 inch riser.  This trunkline terminatedat the first stage gas oil separator (located atop the offshore platform).  Other flow system configuration information includes the following:

North Safaniya Riser System

Well Information:

  • Original Production:  100,000 – 120,000 b/d
  • Crude type:  Arab Heavy (23˚ API / 210 scf/bbl GOR crude oil / 2.55% Sulfur)
  • 12 subsea wells drilled to a depth of approximately 5,000 feet
  • Wellhead pressure 320 psi with a flow bean choke on each well
  • Wells located up to 4 miles from the offshore platform

Flowline System:

  • 90 foot, 24 inch riser to the offshore platform
  • 8 foot x 120 foot separator located on the offshore platform
    • Designed to handle 250,000 b/d
    • Separator operating @ 50 psi
    • Control valve installed at the separator inlet
  • 30 miles to shore from the offshore platform
    • 30 inch line for the pressure crude
    • 8 inch line to take the gas to the shoreline

The Problem: With the system design configuration, oil and gas slugs formed in the 24 inch trunkline/riser system, resulting in large and rapid pressure fluctuations up to 40-50 psi in the vertical riser.  The liquid slugs and gas bubbles then entered the first stage separator, straining its ability to process the unsteady state flow characterized by pressure fluctuations, rapid change in the liquid level, and liquid flooding accompanied by intermittent gas bubbles as they entered the separator.

 Analysis and Solution: Our production facilities simulation software (PRODSIM) indicated that, of the 210 scf/bbl gas in solution at the wellhead, a great deal was evolving out of solution by the time the fluid reached the first stage separator and was thus contributing to the formation of liquid and gas slugs.

Although increasing system backpressure usually decreases the overall flowrate, for this specific configuration, we actually increased the back pressure on the upstream side to 150 psi (from 50 psi originally).  To accomplish this, the platform separator inlet control valve was gradually cut back from a setting of 70 percent to 22 percent.  By progressively cutting back the control valve, the throughput temporarily fell to approximately 60 percent of the prior output.  However, over the following days, this increased back pressure improved the flow regime from slug to bubble flow and improved oil production to roughly 150,000 b/d.

While this increase of back pressure increased production by 30-50,000 b/d, our analysis indicated that production could be further improved by expanding the riser system while maintaining fluid velocities. Over the course of several months, three 10 inch risers were installed in place of the original 24 inch riser.  This modification resulted in production ramping up to 210,000 b/d over the following months—a near doubling of throughput in a matter of months.


Large Trunkline to Shore in the Berri Field, Saudi Arabia

A second example of employing our production facilities software for obtaining innovative solutions to prevent subsea slugging and increasing production involves an oil field with hilly dune-like subsea terrain.  The large size of this 36 inch line played an interesting role in modeling the flowing phenomena of this system.

Prior to system modifications, the trunkline was only producing 150,000 b/d—clearly less than this 36 inch line was designed to handle.  While the initial reaction was to further reduce oil production to avoid fluid flow problems, this lines low throughput was actually at the epicenter of its problem. Ultimately, increasing throughput was precisely what we recommended in order to improve production.

Field Background:

  • Crude Type:  Arabian Extra Light (40˚ API / 760 scf/bbl GOR crude oil)
  • 15 subsea wells drilled to a depth of approximately 8,300 feet
  • Wellhead pressure 550 psi with a flow bean choke on each well
  • 20 miles to shore from the wells
  • First stage separator onshore:  150 foot x 16 foot
    • Designed to handle 350,000 b/d
    • Separator operating at 150 psi


The problem: Long oil and gas slugs were forming in the 36 inch trunkline over the mountainous subsea terrain.  As the 3 phase flow arrived onshore, the separator was repeatedly swamped by slugs although its design capacity was significantly higher than the production it was handling.

Analysis and Solution:  By applying our production facilities software technology to simulate the flow system, we were able to calculate liquid and gas Froude Numbers—approximately 0.1 and 0.16, respectfully.  The system was clearly in Froude Number control as indicated in the flow regime map below and characterized by friction factors several times greater than what they would be if under Reynolds Number control.   Additionally, since our software accounts for changes in elevation and predicts the likely effect that both friction and elevation pressure drop components have on the fluid flow for each successive flow increment, we were able to predict where the long slugs were forming and their relative frequency.

The solution to this flow problem involved two separate measures:

  • [Short-term measure]: Install a pressure sensor approximately 2,000 feet before reaching the onshore separator.  This sensor was installed to identify incoming high pressure surges from liquid slugs and sudden pressure drops from gas bubbles. With this information, we were then able to:
    • Adjust the separator inlet control valve for the imminent arrival of large slugs
    • Position the separator liquid level to minimize liquid carryover and gas carry-under by controlling the settings of the separator gas and liquid exit control valves
  • [Long-term measure]: Drill an additional well to bring additional capacity on-stream—effectively increasing the fluid velocity which, in turn, acts to increase the liquid and gas Froude numbers and results in a decreased friction factor while transitioning from Froude Number to Reynolds number control.

As discussed below, this control strategy successfully kept the 36 inch line in homogenous flow to avoid swamping the separator and accommodated a greater than two-fold increase in separator throughput.  Controlling the separator gas and liquid outlet control valves set the separator liquid level to avoid excess liquid-carry-over and gas-carry-under.

Flow Patterns for Subsea Flowlines

Summary of the results and analysis of the Berri flow system production increase:

  • The new pressure sensor, coupled with adjustment of the control valve, was able to address slugs before they reached the separator by adjusting the separator inlet control  valve setting
  • The gas and liquid outlet valves were controlled to position the separator liquid level so as to minimize separator liquid-carry-over and gas-carry-under at the higher 350,000 b/d production rate.
  • As predicted by our production simulation software, the line flow pattern changed from Froude number to Reynolds number control with an increase in the liquid and gas Froude numbers to 0.23 and 0.37 respectfully. The resultant decrease in friction factor improved the production potential of the entire flow system.
  • While the initial throughput of the Berri trunkline system was 150,000 b/d while operating in slug flow, the field’s production ultimately improved to 350,000 barrels per day with the system flowlines operating in homogeneous flow and the separator operating near its designed capacity.

In addition to the analyses described for the Safanyia and Berri fields, similar analyses were also conducted for the Saudi Marzan and Zuluf offshore oil fields. A recent 2014 SPE paper 170574-MS, C. Sarica et al, “Feasibility and evaluation of surfactants and gas lifting as severe slugging suppression method” acknowledges Yocum as the first to identify multiple severe slugging mitigation techniques (see April 1973 paper 4712 Yocum, B.T. “Offshore  riser slug flow avoidance, mathematical model for design and optimization”). Our mathematical simulation model has continued to evolve since our original work in order to reflect subsea and onshore oil field experience and incorporate the important contributions of Brill, Schmidt and others in analyzing oil, gas, and water (3-phase) flow over various systems.  Our software has been extended to predict water-oil emulsion and hydrate formation, characteristic of deep sea cold temperature flow conditions. Additional subsea projects in which the EnSys Yocum Production Facilities Simulation Model has been applied include:

Forties Field, North Sea (for BP):  Multiphase flow solutions were simulated for alternatives of natural depletion, water injection and gas lift field development scenarios. We also formulated unique solutions to avoid slug flow in risers along with solutions for wax deposits, sand removal and well workovers. Additionally, we developed engineering proposals for construction of 46 deviated wells and gathering systems. Following acquisition of the Forties field by Apache Corporation, more than 115 new wells have been drilled to extend the life of the field by 20 years and a high-pressure gas lift system was installed on the Charlie platform.

Buchan Field, North Sea (for BP):  We developed a comprehensive flow system solution to evaluate gas lift well operations and the process facilities which included oil/water/gas separation and compression required to re-inject gas into the wells. This included modeling well operations from the reservoir, through the reservoir pay, and up the inclined/vertical wells.

Feridoon, Arabian Gulf (for Aramco):  Designed a 60 mile, 24 inch multiphase trunkline gathering and production system which flowed from 4 offshore platforms, each of which had 6 wells, through the field’s separation facilities.

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