Production Engineering

1.  Multi-Phase Flow

This refers to a state of low where there are multiple phases of fluids flowing together in one stream. Multi-phase systems have variations in the flow regimes along the fluid stream and typically there are 4 regimes that have been identified:

  • Bubble – the gas phase is dispersed within the continuous liquid phase
  • Slug – gas bubble coalesce into a large enough volume that it occupies the diameter of the pipe
  • Churn – the bubbles become large enough such that they collapse promoting turbulent flow with both phases being dispersed
  • Annular – gas becomes the continuous phase with the liquid phase entrained within

2.  The Production Facility

This is a facility that separates the well stream into the three phases, be it oil, water and gas. The purpose is to produce saleable products, or to produce a product that can be further refined or processed or even disposed of.

Typically each of the individual phases go on to be processed in an unique way depending on the chemical characteristics of the phase or depending on the limitations of the facility, be it on or offshore, space restrictions or environmental regulations.

2.1.              Separation Process Overview

This process is key to the economics of the field. It allows for the valuable fluids from the well stream to be separated, purified, quantified and sold for financial return. If the streams are of no value either by its very nature, or because of in-sufficient quantities they will be further treated and brought to environmental standards and discharged to the environment. This would most likely apply to the water and gas streams.

The basic fluid flow for the facility is illustrated in the block diagram below. It starts with fluids from the wells being sent to the separator. At this stage the fluid is separated into the three possible fluids, oil, gas and water. The fluid stream of importance is the oil, this is treated and then sold. The water collected from the initial separation and then from the treatment of the oil is to be treated and then dis-charged to the sea. The gas is vented as it is not expected to be in economical values.

2.1.1.   Oil

Because of the nature of produced fluid the higher the pressure of the initial separator the greater the chance of more liquid being obtained in the separator. However too high too may light components will stay in the liquid phase at the separator and be lost to the gas at tank. If the pressure is too low then not as many of these components will be stabilized into the liquid at the separator and will be lost to the gas phase.

Given the fact that this is small facility the pressure of the lowest stage could be set within the range of 25-50psig. This will allow for the oil and water to be dumped to their respective treatment systems. However if higher pressures are used then the amount of energy needed to send the oil to the onshore facilities would be less. A compromise between these two requirements would be to set the operating pressure between 50-100psig.

2.1.1.   Water

In all instances the water will have to be treated for impurities to an environmentally acceptable standard before being released to the sea. For this case the oil concentration limit for the disposed water will be 30mg/l in keeping with international standards.

2.2.              Facilities Components

2.2.1.   The Manifold

This is the piping arrangement that routes the many well streams from the well to a collective singular fluid stream or helps to redistribute the well streams to the proper processes that they are required to go through.

They help to control, monitor and distribute fluid flow from one point en-route to another.

2.2.2.   Separator

This is one of the most critical pieces of equipment that is located and used at production facilities. This piece of equipment does the bulk work of separating the well stream into the most fundamental phases namely oil, gas and water. They are usually cylindrical in nature and may be mounted vertically or horizontally, depending on size, space and fluid requirements. Typically separators are arranged in stages based on pressure loss. This pressure must be properly chosen so as control the proportion of the liquid and vapour phases that will either stabilize or go further downstream and may be potentially lost.

2.2.3.   Pumps

These help to move the fluid around the facility through the facility piping. They are also used to move the respective fluid streams through the LACT or metering unit after these fluids have completed their movement through the proper process. In addition they are used to move the fluid quantities from the facility to other point for further processing.

2.2.4.   Water Treatment

This is the way in which we handle the produced water from the reservoir. In many instances this fluid is produced and is of no monetary value and is ultimately disposed of. However it does not mean it is not processed in any way. Far from it is appropriately handled so as to remove as much hydrocarbons as is possible, this allows for the accumulation of the maximum amount of saleable hydrocarbons.

Given the fact that the water is eventually disposed of it must be treated so as to meet environmental standards. This is especially of concern in offshore and marine environments.        Governing Principles

Such treatment systems take advantage of gravity separation to promote oil droplet flotation. It also used dispersion and coalescence which promotes the gathering of oil droplets thus aiding with their separation from the water phase.        Typical Equipment

Settling Tank – the simplest piece to be used designed to provide long residence time which promote coalescence and gravity separation.

Coalescers – skim tanks that use internal plates to improve the gravity separation process. These plates provide a surface to promote coalescence and gravity separation. They may be either parallel or corrugated plate interceptors.

Hydrocyclones – these use centrifugal forces to help remove oil droplets from water.

Disposal/Skim Piles – used primarily in offshore and marine environments. They consist of an open ended pipe attached to the platform extending below the water line. They are usually used as a point to dispose of water after it has been treated by the facilities. The centralized disposal of all the facility’s water allows for better monitoring of the effluent and prevents unnecessary spreading of sheens from the residual oil.

The skim pile is a type of disposal pile with internal baffles that aids in residence time.

3.  Two/Three Phase Oil and Gas

This type of fluid phase separation is done with the separator.

3.1.              Factors Affecting Separation

  1. Fluid inflow rates
  2. Operating temperatures and pressures
  3. Surge/Slug and foaming tendencies
  4. Inflow fluid properties
  5. Design parameters
  6. Inflow fluid impurities
  7. Corrosive tendencies of fluids

3.2.              Principles of Separation

  • Centrifugal inlet to provide primary separation of liquid and gas
  • Adequate dimensions/volume characteristics to promote settling and provide surge room
  • Mist extractor/eliminator to coalesce small particles of liquid
  • Provides adequate level control and instrumentation to properly monitor and manipulate fluid volumes/levels within the device and to allow for SAFE operation.

3.3.              Gas Liquid Separation

The most important duty of fluid processing. A properly designed separator must:

  1. Primary phase separation of liquid hydrocarbons
  2. Refine the primary separation by removing entrained liquid
  3. Further refine separation by removing entrained gas from liquid
  4. Dis-charge the separated fluid gas/liquid streams in such a manner that NO RE-ENTRAINMENT occurs.

3.4.              The Separator

This is critical component in the separation process, one that does the bulk work of handling and sorting the well-stream fluids.

3.4.1.   Components        Inlet Diverter

Reduces the inlet momentum aiding in phase separation at the inlet stage. It can be considered the primary separation.        Fluid Collection

Usually the lower section of the vessel that provides the volume necessary to promote fluid accumulation and retention time.        Settling Section

This section promotes further settling by gravity.        Mist Extraction

This is located at the gas phase output, the mist extractor helps with the coalescing of small droplets of fluid still entrained in the gas phase and allows for it to rejoin the liquid phase.

3.5.              Sizing a Separator

3.5.1.   Vertical Separator

  1. Calculate CD
  2. Iterate to find Vt, Re and CD. Stop when values converge.
  3. Calculate Gas Capacity Constraint
  4. Calculate the Liquid Capacity Constraint
  5. Compute values for diameter and height for various residence times
  6. Compute the seam to seam length
  7. Compute slenderness ratio
  8. Choose a reasonable size with a diameter greater then gas capacity constraint.

3.5.2.   Horizontal Separator

  1. Calculate CD
  2. Iterate to find Vt, Re and CD. Stop when values converge.
  3. Calculate Gas Capacity Constraint
  4. Calculate the Liquid Capacity Constraint
  5. Compute values for diameter and height for various residence times
  6. Compute the seam to seam length
  7. Compute slenderness ratio
  8. Choose a reasonable size with a diameter greater then gas capacity constraint.

4.  Compressors

These are used to increase the pressure from the incoming well streams to facilitate the transportation/transmission. This is particularly useful for where gas fields are located in remote areas and the gas needs to be delivered to the market or industry.

4.1.              Compressor Type

  1. Jet
  2. Rotary
  3. Centrifugal

Jet compressors use fluid flow to help compress and further propel the gas.

4.2.              Rotary Compressors

They exist in either blower or centrifugal type and are primarily used in distribution facilities where the suction to dis-charge pressure difference is not greater than 15psi.

As mechanical devices they cheap to install and operate owing to the fact that they have few moving parts, requiring minimum floor space a key consideration in offshore and marine facilities. They do have a high capacity that if properly configured in series and can increase the total process compression ratio.

However they are noisy to operate, can overheat and can’t accommodate high pressures.

4.3.              Reciprocating Compressor

Common in the gas industry built for all pressures and capacities. However because it has more moving parts the mechanical efficiency it low. Typically because they are tend to be large they are powered by steam or gas.

It is the duty of the engineer to properly select the compressor to suit the conditions the device will fulfill.

5.  Gas Lift

This is the technology used to increase the oil production rate. It involves the injection of compressed gas into lower sections of tubing. Upon entering the tubing the compressed gas helps to push the oil to the surface and aerates the oil thus lowering the effective density.

In this case the depth of the well is of no problem, and it is suitable for both on and offshore environments, lifting costs for a large number of wells is generally low. It however requires that lift gas be near the oil fields and gas compression equipment must be near. For small fields this may not be practical or efficient.

The complete system usually consists of a compression station, an injection manifold and tubing string with unloading valves. Other pieces of equipment:

  1. Main operating valves
  2. Wire line adaptations
  3. Check valves
  4. Mandrels
  5. Surface control equipment
  6. Compressors

The Advantages:

  1. Deep injection depths can be achieved
  2. Varying the valve depth placement can affect the well productivity
  3. Gas Volumes injected can be properly metered
  4. Intermittent gas injection can be used to “kick-off” a well

Typically it is applied to wells with a reasonable degree of bottom hole pressure maintenance, and a productivity index (PI) of approximately 0.5bbl/day/psi or greater.

6.  Metering

This is done with an LACT unit, they are made to API specifications in addition to any other additional measuring and sampling standards that are required. They not only measure the quantity of fluids but the solids and water content. It can is properly configured can allow for the fluid stream to be diverted for further processing. In other cases it may just sound an alarm for the plant operator to take the appropriate actions.

7.  IPR

This is graphical representation of a wellbore’s performance, it is relationship between the flowing bottom hole pressure and the liquid production/flow rate.

8.  Well Problem

Depending on the well these problems may vary.

For oil:

  • Low Productivity
  • Excessive gas production
  • Excessive water production
  • Sand production

For gas:

  • Low productivity’
  • Excessive water production
  • Liquid loading
  • Sand production

8.1.              Low Productivity

The lower than expected productivity based on comparing actual production and production by nodal analysis.

Attributed to

  • Over estimation of reservoir pressure and permeability
  • Formation damage
  • Reservoir heterogeneity
  • Poor completion
  • Wellbore restrictions

8.2.              Excessive water production

Usually from water zones not connate water. Typically fluid density logs are useful for identifying water zones. A spinner flow meter can give an idea where the water is coming from.

8.3.              Excessive gas production

May be due to channeling behind the casing through micro annuli in the cement. Can be caused by preferential flow from one formation to one of the gas coning or casing leaks. Production logs can help to determine channeling and coning, typically a temperature log. Density logs can be used to identify the gas zones that existed behind the casing.

8.4.              Liquid loading in the gas will

Gas Wells produce liquid water and/or condensate in the form of a mist. When the gas velocity drops the liquid begins to accumulate in the well bore. This increases the bottom hole pressure and decreases the production rate.

Using smaller tubing sizes can help or the well it can be unloaded by gas lift or by pumping it out. The well ball can be heated all water can be injected. However this problem is not always obvious and recognizing the liquid loading is not easy.

9.  Carbon Dioxide

9.1.              Properties

  • A molecular weight of 44.01 lb/lb-mol
  • Can exist as a solid, liquid and gas depending on the temperature and pressure
  • In its gaseous form it is colourless, odourless and non-flammable
  • It is the fourth most abundant gas in the atmosphere
  • Is generated by the human body as a result of cellular respiration

9.2.              Exposure

9.3.              Fluids Treatment

The gas is produced in the well streams of oil and gas wells. Typically its removal refers to a process known as sweetening.

The removal of the carbon dioxide will

  • improve the heating value of the gas
  • prevent the corrosion of pipelines
  • prevent crystallization of the gas during the liquefaction

9.4.              Treatment Options

  • Absorption process
    • Using organic chemical to absorb the gas
  • Adsorption process
    • Uses a chemical reaction to remove the gas from the stream
  • Alkaline Salt process
    • Again using a chemical reaction to remove carbon dioxide gas, using potassium carbonate
  • Physical Separation
    • Membrane Separation – using barriers to selectively allow the permeation of certain gases
    • Cryogenic – using low temperatures to distill carbon dioxide from the well stream
  • Hybrid Solution
    • Using a combination of physical and chemical processes to separate the gas from the well stream

9.5.              Corrosion

This is usually the result of dissolved carbon dioxide in the water, this lends to the formation of an acidic liquid that can damage process equipment.

10.      Hydrogen Sulphide

10.1.          Treatment Options

  • Scavenger Chemicals
    • Cost effective
    • Efficient without producing harmful by products
    • Safe to handle (Non-Toxic)
  • Alkaline based products
    • Treatment with caustic soda
    • Relatively inexpensive
    • Needed in large quantities, and may be toxic in high concentrations
  • Regenerative Amine products
    • Used in high volume gas treatments
  • Liquid Redox
    • Effective scavenger as it is highly reactive to hydrogen sulphide
    • Typically uses chlorine dioxide which is corrosive and unstable
  • Non-Regenerable solid adsorbents
    • Usually involves a bed of solid particles that comes into contact with the gas, eventually the bed is removed to be replaced or regenerated.
  • Physical Solvent process
    • Typically a proprietary process
  • Conversion of hydrogen sulphide to sulphur
    • Chemically convert the hydrogen sulphide to sulphur
  • Squeeze treatments
    • Applying hydrogen sulphide treatments to the reservoir and wellbore using well equipment and pumps.

10.2.          Corrosion

Hydrogen sulphide can cause stress cracking which leads to the degradation of process and pipeline equipment. In addition the toxicity of the gas means that it is a health hazard to human personnel if it is leaked to the atmosphere.

11.      Bibliography

Arnold, Ken , and Maurice Stewart. Surface Production Operations. Burlington, MA: Gulf Professional Publishing, 2008.

Guo, Boyun , Williams C. Lyons , and Ali Ghalambor. Petroleum Production Engineering. Elsevier Science & Technology Books, 2007.


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