Natural Gas Engineering

1.  What is Natural Gas?

A mixture of hydrocarbons and varying quantities of non-hydrocarbons that exist in the gaseous phase or in solution with crude oil in underground reservoirs.

This is a subcategory of petroleum that is naturally occurring complex mixture of hydrocarbons. It may contain a minor amount of inorganic compounds not all of which may be combustible and able to fetch a price on the market.

1.1.              Conventional Gas

Gas in tight sands and shales, coal bed methane, gas in geo-pressured reservoirs and gas from gas hydrates.

It can be either associated or non-associated. Associated gas and dissolved gases are both found with crude oil. Dissolved gas is that which is dissolved in the crude. Associated is free gas in contact with crude oil. All crude oil reservoirs contain dissolved gas and may or may not contain associated gas. Non-associated gas is found in a reservoir that contains a minimal quantity of crude oil.

Gas in tight sands occur in formations of permeabilities 0.001 to 1.0md. Gas hydrates are snow like solids in which each water molecule forms hydrogen bonds with 4 of the nearest water molecules to build a crystalline lattice structure that traps gas molecules in its cavities.

1.1.1.   Retrograde Gas

It has a phase diagram that is smaller than that of oils with a critical point further down the left side of the envelope. They are the result of the gases containing fewer heavy hydrocarbons than the oils. The critical temperature is less than the reservoir temperature and a cricondentherm greater than reservoir temperature. Initially they are totally gas in the reservoir but as reservoir pressure decreases the gas exhibits a dew point. As the pressure is reduced liquid condenses to form free liquid in the reservoir. This will normally NOT flow and can’t be produced.

 

1.1.2.   Wet Gas

Predominantly smaller molecules will lie below reservoir temperature. They exist solely as a gas in the reservoir, throughout the reduction of reservoir pressure. No liquid is formed in the reservoir. The separator conditions lie within the phase envelope as such liquid is formed on the surface.

1.1.3.   Dry Gas

Primarily methane with some intermediates. No liquid is formed in the reservoir and at the surface. They are the easiest to deal with because no liquid condenses as the gas comes to the surface. Surface separation and densities equal that of the reservoir.

2.  Utilization

Natural gas has many uses depending on its composition. It has far ranging uses from residential heating to transportation which is by far the smallest segment. The two largest consumers of natural gas are industry and utilities, usually as a feedstock for chemical processes and power generation.

Typical Utilization:

  1. Compressed natural gas (CNG)
  2. Liquified natural gas (LNG)
  3. Gas to ammonia and urea
  4. Gas to liquids – Fischer Tropsch route
  5. Gas to methanol
  6. Gas to power

3.  Gas Project Life Cycle

3.1.              Geoscience

At this stage the petroleum system is looked at. The reservoir type, the trap that promotes accumulation and the source of the hydrocarbon s identified. Typically this is done by mapping the area and by the analysis of seismic data. If it is available then mud logging data and core samples are consulted.

3.2.              Exploration

In this phase areas of potential are identified. The geological features identified in the geoscience phase are assessed, and a more detailed geological framework is developed. The rock, fluid and pressure properties are better defined, this leads to the estimates of the hydrocarbon volumes in place. The decision to drill further and evaluate is made.

3.3.              Assessment Phase

Better and greater attempts made at characterizing the reservoir. Try to determine the geometry and continuity. Plans will be made for a long term drilling campaign. Estimation of the recoverable hydrocarbons will be made again and refined as needed.

3.4.              Reservoir Analysis

  1. How much worthwhile producible fluid is there?
  2. How much of it can be recovered and how long will it take to do so?
  3. How many wells and what type of wells do we need to produce this reservoir?
    1. Do we have the capital and technology?
  4. What are the chances of success?
  5. Will the project turn a profit?

3.5.              Drilling

  1. The well profile.
  2. The casing selection both the setting depths and the type and grade of casing to be used.
  3. The details of the drilling and rig operations.
  4. Management of the financial resources allocated to the operations.
  5. Troubleshooting operational decisions as they occur.

3.6.              Completion

  1. Develop completion procedure.
  2. Pick the perforations based on the open hole logs.
  3. Run cased hole logs to evaluate the cement job and diagnose and determine solutions to any such problems.
  4. Design post completion jobs to be performed on the producing formation.
  5. Produce from the well with minimal cost.
  6. Negotiate with service providers.

3.7.              Production

Concerned primarily with the transportation, gathering and eventual distribution and sale of the produced fluids. They essentially handle the fluid until they reach the delivery point.

They move the oil and gas from the well reservoir/wellbore to the final sales point. They are required to gather the fluids, treat and condition the fluids so that they meet delivery expectation conditions and specifications. Production is also responsible for the transportation of said fluids from the reservoir/wellbore to the appropriate points. This would require engineering in the appropriate lift mechanism as well the use of pumps and compressors to efficiently move the fluids form one point to another.

Specifically they will probably rat the fluids for undesirable compounds like hydrogen sulphide and carbon dioxide to name a few.

This particular segment will be responsible for the long term management of the wells, the aim of which is to maximize production and minimize cost and expenditure on the well.

3.8.              Marketing

This would involve the sale of the oil and gas to prospective buyers. This may involve further refining or compression and eventual transportation and metering. A good example is the liquifiation of natural gas. The gas is compressed and liquefied and loaded unto ships to be transported to buyers. The same can be said of oil tankers that are loaded and used to transport oil to other areas.

Marketing will also be responsible for negotiating contracts between the seller and the buyer in the case of the two parties having an arrangement. If not the product can be placed on the open market and the market price can determine the selling price.

4.  Properties

The properties of natural gas vary depending on the pressure, temperatures and the other chemicals and substances it comes into contact with. Knowledge of these properties and their interaction with each other can help to calculate and predict the fluids behavior.

Typically the gas composition is found by lab measurements.

5.  Gas Treatment

The gas stream as it comes from the reservoir depending on the purity may need to be properly processed. Some streams may only require minimal processing in the form of dehydration other streams with more complex compositions may need more sophisticated forms of processing.

Field processing removes undesirable components and separates the wellstream into salable gas and hydrocarbon fluids.

The aim of processing:

  1. To remove condensable and recoverable hydrocarbon vapours
  2. To remove condensable water vapour which depending on conditions may promote hydrate formation
  3. To remove undesirable compounds

It can be said that the fluid composition will determine the design criteria for the sizing and selection of the separator and treatment processes for the hydrocarbon stream.

5.1.              Gas-Liquid Separation

Arguably one of the most important duties of gas processing: to separate the gas from free liquids. A properly designed separator will perform the following functions:

  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 the no re-entrainment occur

5.2.              Principles of Separation

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

5.3.              Treatment

Typically natural gas treatment involves the dehydration of the gas before compression or transportation. The primary reason for dehydration is to remove water vapour which if left in the gas stream may promote the formation of hydrates. In addition when the water is present in the gas stream carbon dioxide and hydrogen sulphide may become corrosive liquids, the water may also promote slugging flow regimes reducing the pipeline flow efficiency and lastly water content decreases the heating value of the natural gas. Dehydration can be accomplished by cooling, adsorption and or absorption.

5.4.              Compression

This is used to increase the pressure of the stream for the purposes of transportation. Via pipeline. In general compression and compressors are use to increase the potential energy needed for the movement of the gas stream. Compressors are usually located at a centralized point, relative to the wells they are fed by, and are used to collect and compress the gas stream for further transportation. Typically they are sized based on the input pressure and the expected volume they will handle.

6.  Gas Measurement

6.1.              Orifice meter

This is a means of measuring the pressure drop caused by the velocity change of the gas as it passes through an engineered restriction within the pipe and as a result its flow path.

The most common instrument used in the measurement of natural gas flow rate. It is typically used because of the level of accuracy it delivers, the ruggedness, simplicity, ease of installation, and maintenance, range, capacity and low cost.

It is comprised of 2 major element:

  1. To produce the differential pressure
  2. To measure the pressure

7.  Compositional Analysis

These are conducted in a laboratory so as to obtain better understanding of the gas behavior within the reservoir and as they are produced and the reservoir pressure is reduced. They include:

  1. Constant Compositional Expansion Tests
    1. Saturation Pressure
    2. Isothermal Compressibility
    3. Compressibility factor
    4. Total hydrocarbon volume as a function of pressure
  2. Differential Liberation Test
    1. Amount of gas in solution
    2. Oil shrinkage as a function of pressure
    3. Evolved gas properties
    4. Oil density as a function of pressure
  3. Separator Tests – conducted to determine the volumetric changes to the reservoir fluid as it passes through the separator onto the storage tank.

8.  Transmission

Typically this is accomplished with the use of pipelines which move the gas from one point to another. They provide an economical method for transporting the fluids over great distances, with low operating costs especially as the volumes increase.

However the design of the pipeline system one must take into consideration the fluid properties as it is compressed and moved along the pipeline. As such mathematical models are used to determine the bahaviour of the fluid as it travels along the pipeline. This helps to determine the pressure loss to be had by the volume of fluid and as such one can better determine the horsepower needed to move the gas via the pieline.

Several Equations have been developed to determine the pressure loss. Among them are:

  1. Darcy’s Equation
  2. Liquid Flow
  3. Hazen-Williams
  4. Gas Flow
  5. Weymouth Equation
  6. Panhandle A
  7. Panhandle B
  8. Spitzglass
  9. Cullender and Smith
  10. Pressure drop based on elevation change (API RP 14E)
  11. Pressure Loss as a result of pipe fittings.
    1. Resistance Co-efficient
    2. Flow Co-Efficient
    3. Laminar Co-Efficient

Bibliography

Guo, Boyun, and Ali Ghalambor. 2005. Natural Gas Engineering Handbook. Houston Texas: Gulf Publishing.

Ikoku, Chi U. 1992. Natural Gas Production Engineering. Malabar Florida: Kriegar Publishing.

Smith, R.V. 1990. Practical Natural Gas Engineering. Tulsa Oklahoma: PennWell Publishing Company.

 

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