Separation


Some wells have pure gas production which can be taken directly to gas treatment and/or compression. More often, the well gives a combination of gas, oil and water and various contaminants which must be separated and processed. The production separators come in many forms and designs, with the classical variant being the gravity separator.


                                       


In gravity separation the well flow is fed into a horizontal vessel. The retention period is typically 5 minutes, allowing the gas to bubble out, water to settle at the bottom and oil to be taken out in the middle. The pressure is often reduced in several stages (high pressure separator, low pressure separator etc.) to allow controlled separation of volatile components. A sudden pressure reduction might allow flash vaporization leading to instabilities and safety hazards.


Test Separators and Well test


Test separators are used to separate the well flow from one or more wells for analysis and detailed flow measurement. In this way, the behavior of each well under different pressure flow conditions can be determined. This normally takes place when the well is taken into production and later at regular intervals, typically 1-2 months and will measure the total and component flow rates under different production conditions. Also undesirable behavior such as slugging or sand can be determined. The separated components are also analyzed in the laboratory to determine hydrocarbon composition of the Gas oil and Condensate.

The test separator can also be used to produce fuel gas for power generation when the main process is not running. In place of a test separator one could also use a three phase flow meter to save weight.






















Production separators


The main separators are gravity type. On the right you see the main components around the first stage separator. As mentioned the production choke reduces will pressure to

the HP manifold and First stage separator to about 3-5 MPa (30-50 times atmospheric pressure). Inlet temperature is often in the range of 100-150 degrees C. On the example platform, the well stream is colder due to Subsea wells and risers.

The pressure is often reduced in several stages; here three stages are used, to allow controlled separation of volatile components. The purpose is to achieve maximum liquid recovery and stabilized oil and gas, and separate water. A large pressure reduction in a single separator will cause flash vaporization leading to instabilities and safety hazards.

The retention period is typically 5 minutes, allowing the gas to bubble out, water to settle at the bottom and oil to be taken out in the middle. In this platform the water cut (percentage water in the well flow) is almost 40% which quite high. In the first stage separator, the water content is typically reduced to less than 5%.

At the crude entrance there is a baffle slug catcher that will reduce the effect of slugs (Large gas bubbles or liquid plugs). However some turbulence is desirable as this will release gas bubbles faster than a laminar flow.

At the end there are barriers up to a certain level to keep back the separated oil and water. The main control loops are the oil level control loop (EV0101 20 above) controlling the oil flow out of the separator on the right, and the gas pressure loop at the top.(FV0105 20 above) These loops are operated by the Control System. An important function is also to prevent gas blow-by which happens when low level causes gas to exit via the oil output causing high pressure downstream. There are generally many more instruments and control devices mounted on the separator. These will be discussed later.

The liquid outlets from the separator will be equipped with vortex breakers to reduce disturbance on the liquid table inside. This is basically a flange trap to break any vortex formation and ensure that only separated liquid is tapped off and not mixed with oil or water drawn in though these vortices. Similarly the gas outlets are equipped with demisters, essentially filters that will remove liquid droplets in the gas.

Emergency Valves (EV) are sectioning valves that will separate the process components and blow-down valves that will allow excess hydrocarbons to be burned off in the flare. These valves are operated if critical operating conditions are detected or on manual command, by a dedicated Emergency Shutdown System. This might involve partial shutdown and shutdown sequences since the flare might not be able to handle a full blow-down of all process sections simultaneously.

A 45.000 bpd design production with gas and 40% water cut this gives about 10 cubic meters from the wellheads per minute. There also needs to be enough capacity to handle normal slugging from wells and risers. This means the separator has to be about 100 cubic meters, e.g. a cylinder 3 m in diameter and 14 meters long. At the rated operating pressure this means a very heavy piece of equipment, typically around 50 tons for this size. This limits the practical number of stages. Other types of separators such as vertical separators, cyclones (centrifugal separation) can be use to save weight, space or improve separation.There also has to be a certain minimum pressure difference between each stage to allow satisfactory performance in the pressure and level control loops.

Chemical additives are discussed later.


















Second stage separator


The second stage separator is quite similar to the first stage HP separator. In addition to output from the first stage, it will also receive production from wells connected to the Low Pressure manifold. The pressure is now around 1 MPa (10 atmospheres) and temperature below 100 degrees C. The water content will be reduced to below 2%.

An oil heater could be located between the first and second stage separator to reheat the oil/water/gas mixture. This will make it easier to separate out water when initial water cut is high and temperature is low. The heat exchanger is normally a tube/shell type where oil passes though tubes in a cooling medium placed inside an outer shell.


Third stage separator


The final separator here is a two phase separator, also called a flash-drum. The pressure is now reduced to about atmospheric pressure (100 kPa) so that the last heavy gas components will boil out. In some processes where the initial temperature is low, it might be necessary to heat the liquid (in a heat exchanger) again before the flash drum to achieve good separation of the heavy components. There are level and pressure control loops. As an alternative, when the production is mainly gas, and remaining liquid droplets have to be separated out, the two phase separator can be a Knock-Out Drum (K.O. Drum).


Coalescer


After the third stage separator, the oil can go to a coalescer for final removal of water. In this unit the water content can be reduced to below 0.1%. The coalescer is completely filled with liquid: water at the bottom and oil on top. Inside electrodes form an electric field to break surface bonds between conductive water and isolating oil in an oil water emulsion. The coalescer field plates are generally steel, sometimes covered with dielectric material to prevent short circuits. The critical field strength in oil is in the range 0.2 to 2 kV/cm. Field intensity and frequency as well as the coalescer grid layout is different for different manufacturers and oil types.


Electrostatic Desalter


If the separated oil contains unacceptable amounts of salts, it can be removed in an electrostatic desalter (Not used in the Njord example) The salts, which may be Sodium, Calcium or Magnesium chlorides comes from the reservoir water and is also dissolved in the oil. The desalters will be placed after the first or second stage separator depending on Gas Oil Ratio (GOR) and Water cut.


Water treatment


On an installation such as this, when the water cut is high, there will be a huge amount of produced water. In our example, a water cut of 40% gives a water production of about 4000 cubic meters per day (4 million liters) that must be cleaned before discharge to sea. Often this water contains sand particles bound to the oil/water emulsion.

The environmental regulations in most countries are quite strict, as an example, in the North-East Atlantic the OSPAR convention limits oil in water discharged to sea to 40 mg/liter (ppm). It also places limits other forms of contaminants. This still means up to one barrel of oil per day for the above production, but in this form, the microscopic oil drops are broken down fast by natural bacteria.

Various equipment is used; the illustration shows a typical water treatment system. Water from the separators and coalescers first goes to a sand cyclone, which removes most of the sand. The sand is further washed before it is discharged.

The water then goes to a hydrocyclone, a centrifugal separator that will remove oil drops. The hydrocyclone creates a standing vortex where oil collects in the middle and water is forced to the side.

Finally the water is collected in the water de-gassing drum. Dispersed gas will slowly rise to the surface and pull remaining oil droplets to the surface by flotation. The surface oil film is drained, and the produced water can be discharged to sea. Recovered oil in the water treatment system is typically recycled to the third stage separator.




 

Separation of Oil and Gas

Oil & Gas Production SitemapOil-and-Gas-Production-Foundation.htmlshapeimage_2_link_0
Drilling Sitemaphttp://www.sereneenergy.org/shapeimage_3_link_0

  1. Oil and Gas Production

  2. Production Technology Foundation

  3. Company Operations contribution

  4. Timescale of Involvement of PT

  5. Topics within Production

  6. Well Completion

  7. Well Stimulation

  8. Associated Production Problems

  9. Remedial and Workover Techniques

  10. Oil & Gas Production System

  11. Group Gathering Station

  12. Gas Compression Plant

  13. Gas Collection station

  14. Crude Tank farm

  15. Effluent Treatment Plant

  16. Central Water Injection Plant

  17. Oil & Gas Production Introduction

  18. Crude Oil and Natural Gas

  19. Petroleum Industry History

  20. Oil & Gas Production Overview

  21. Oil & Gas Production Facilities

  22. Overview of Wellhead

  23. Manifold, gathering and separation

  24. Separation of Oil and Gas

  25. Metering, storage and export

  26. Gas Treatment and Compression

  27. Gas Properties

  28. Mass and Weight

  29. Volume

  30. Density, Specific Weight and Specific Volume

  31. Viscosity

  32. Ideal Gases

  33. Real Gases

  34. Heating Value

  35. Formation Damage

  36. Radial Flow and Formation Damage

  37. Radial flow

  38. Near Wellbore Flow Restrictions

  39. Potential Formation Damage Mechanisms

  40. Causes and Effects of Sand Production

  41. Nature of Sand Production

  42. Effects of Sand Production

  43. Causes of Sand Production

  44. Predicting Sand Production

  45. Operational and Economic Influences

  46. Formation Strength Log

  47. Sonic Log

  48. Formation Property Log

  49. Porosity

  50. Drawdown

  51. Finite Element Analysis

  52. Time Dependence

  53. Multiphase Flow

  54. Sand Control Techniques

  55. Maintenance and Workover

  56. Rate Exclusion

  57. Plastic Consolidation

  58. High Energy Resin Placement

  59. Resin Coated Gravel

  60. Slotted Liners or Screens without Gravel Packing

  61. Slotted Liners or Screens with Gravel Packing

  62. Gravel Pack Sand Design

  63. Formation Sand Sampling

  64. Sieve Analysis

  65. Gravel Pack Sand Sizing

  66. Gravel Pack Sand

  67. Gravel Pack Sand Substitutes

  68. Slotted Liner and Wire Wrapped Liners

  69. Slotted Liner and Wire Wrapped Liners

  70. Slotted Liners

  71. Wire Wrapped Screens

  72. Prepacked Screens

  73. Flow Capacities of Screens and Slotted Liners

  74. The Excluder

  75. Erosion Test for Sand Control

  76. Gravel Pack Completion Equipment and Service Tools

  77. Sump Packer

  78. Seal Assemble for Gravel Pack

  79. Gravel Pack Screen ; Blank Pipe

  80. Shear Out Safety Joint and Knock out Isolation Valve

  81. Gravel Pack Extension Packer

  82. Gravel Pack Service Tool

  83. Open Hole Gravel Pack Completion Equipment

  84. Well Preparation for Gravel Packing

  85. Drilling Practices

  86. Cleaning the Casing Open Hole Work String ; Surface Facilities

  87. Filtration for Gravel Packing

  88. Completion/Gravel Pack Fluids

  89. Open Hole Gravel Packing

  90. Guidelines for Selecting Open Hole Gravel Pack Candidates

  91. Top Set Open Hole Gravel Pack

  92. Gravel Pack Equipment and Gravel Placement

  93. Set Thru Open Hole Gravel Pack

  94. Oil and Gas Pipeline

  95. Design of Marine Pipeline

  96. Pipeline Installation Introduction

  97. Offshore Pipeline Functional Req.

  98. Offshore Pipeline Authorities’ Req.

  99. Environmental Impact

  100. Pipeline Operational Parameters

  101. Pipeline Size Determination

  102. Flow Simulation in Pipeline

  103. Geophysical Pipeline Site

  104. Investigation Survey

  105. Geotechnical Pipeline Site

  106. Investigation Survey

  107. Soil Sampling & In-Situ testing

  108. Wind, Waves and Current

  109. Collection of Wave Data

  110. Linepipe Materials

  111. Strength, toughness, Weldability

  112. Steel Microstructure

  113. Oil & Gas Terminology

  114. A    B    C    D    E    F    G    H    I    J    K    L    M    N    O    P    Q    R    S    T    U    V    W    X    Y    Z  

  115. Offshore Pipeline Terminology

  116. Petroleum Videos

  117. Peak Oil Video

  118. Oil and Gas Economics

  119. Ghana Oil and Gas Production

  120. Oil and Gas Well Drilling

  121. Well Completion

  122. Artificial Lift Techniques