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Category: Gas Processing Plant

Mercury Removal in Oil and Gas Processing Facilities

Rifka Aisyah Leave a comment

Mercury (Hg) can be present in feed gas in wide range of concentrations. It is important to remove mercury from the feed gas to avoid mercury attack on the brazed aluminum heat exchangers. Aluminum material is highly reactive with mercury and can be corroded quickly resulting heat exchangers failure and potentially can pose environmental and safety hazards. In addition, mercury will also cause poisoning precious metal catalyst if it presents in petrochemical process. This post outlines the method on mercury removal in oil and gas processing facilities.

Mercury Removal in Oil and Gas Processing Facilities
Mercury Removal in Oil and Gas Processing Facilities

Mercury presents in most natural gas field in concentration ranging from less than 10 ppb to more than 1 ppm as elemental (metallic), organic, and inorganic compound. Due to its strong affinity for higher molecular weight fractions, mercury predominantly concentrates within the liquid phase rather than the gas stream. Read More

Sizing of Amine System for Natural Gas Sweetening

Rifka Aisyah

In this post I want to share how to size amine system for natural gas sweetening, especially for MEA and DEA. For other amine systems, the licensee should be contacted for detailed design information. In the end of this post, I share simple spreadsheet on how to estimate amine circulation rate, minimum contactor diameter, and reboiler duty of amine system.

Amine absorber

Amine absorbers provide intimate mixing between amine solution and sour gas. Typically, small diameter towers use stainless steel packing, while larger towers use stainless steel trays.

For preliminary design, a tray spacing of 24 in and a minimum diameter of capable of separating 150 to 200 micron droplets can be assumed. The size of packed towers must be obtained from vendor.

Commonly, amine absorbers are equipped with integral gas scrubber section in the bottom of the tower. The function of the scrubber is to remove entrained water and hydrocarbon liquids from the gas, therefore it protects amine solution from contamination.

Separate scrubber vessel can also be provided so that the tower height can be decreased. The vessel should be design using two-phase separators.

For MEA systems with large gas flow rate, a scrubber should be considered for the outlet sweet gas. It is because it will be helpful to reduce MEA losses in the overhead sweet gas. DEA systems do not require scrubber because vapor pressure of DEA is very low. Read More

Sizing Iron Sponge Units for Sulfur Removal in Natural Gas

Rifka Aisyah 1 Comment

In last post we learned about one type of sulfur removal which is using iron sponge unit. Brief review, iron sponge is economically applied for gas containing small concentration of hydrogen sulfide, usually below 300 ppm. Iron sponge unit can not be used to remove carbon dioxide.

In this post, I want to continue the topic about iron sponge unit. More specifically about how to preliminary size iron sponge unit.

At least there are four parameters that we want to know in sizing iron sponge units:

  1. Minimum diameter of iron sponge vessel
  2. Maximum diameter of iron sponge vessel
  3. Required bed height
  4. Quantity of iron sponge
  5. Bed life of iron sponge between change out

Vessel Diameter

Why do we need to know minimum diameter of iron sponge vessel? Read More

Gas Sweetening using Iron Sponge Process

Rifka Aisyah 1 Comment

Iron sponge process is economically applied for gases containing small concentration of hydrogen sulfide (H2S), usually less than 300 ppm, operating from low to moderate pressure in a range of 3.45-34.5 barg (50-500 psig). Iron sponge process cannot be used to remove carbon dioxide.

Iron sponge process is the oldest and still the most widely used batch process for sweetening of natural gas and natural gas liquids. Overall, iron sponge process has the following characteristics which make it still attractive to be applied: simple process, low capital cost, and relatively low chemical (iron oxide) cost. Furthermore, pressure has a relatively little effect on its adsorptive capacity of a gas sweetening agent. Read More

Gas Dehydration Design with Glycol Solutions

Rifka Aisyah

Natural gas contains many contaminants, one of them is water. When the gas is transmitted to the surface from processing and finally pipeline transmission, its pressure and temperature reduced naturally in the well string. This reduce the capacity of natural gas to hold water vapor and free water is condensed. The water vapor must be reduced to meet sales gas requirement, which is usually around 2-7 lb/MMscf.

For many years, glycol solutions have been used for natural gas drying. Early glycol dehydration units utilized diethylene glycol (DEG). Triethylene glycol (TEG) came into use around 1950 primarily because its higher boiling point thus gives better separation of water and greater dew point depression without causing thermal decomposition of the glycol. Tetraethylene glycol (T4EG) has been used in some specialized cases, but in majority, triethylene glycol is used.

In this post, I want to share preliminary design of gas dehydration unit using glycol solutions. Calculation and formulae used in this post can be accessed through this link. Read More

Hydrate Prediction using Pressure-Temperature Correlation

Rifka Aisyah 1 Comment

A hydrate in natural gas system is a physical combination of water and other small molecules to produce a solid which has an “ice-like” appearance but has a different structure than ice. It resembles dirty ice but has voids into which gas molecules will fit. Most common compounds found in gas hydrate are water, methane, and propane, or water, methane, and ethane.

Hydrate formation in natural gas transmission pipeline
Hydrate formation in natural gas transmission pipeline

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Get to Know Glycol Dehydration Unit

Rifka Aisyah Leave a comment

Natural gas dehydration unit is one of important facilities in natural gas processing. Purpose of water vapor removal in natural gas are to prevent gas hydrates formation and to reduce corrossion in pipeline. There are several methods of gas dehydration, which are absorption with liquid desiccant, adsorption with solid desiccant, and cooling below initial dew point. Selection of the method is depend on water content in feed gas and required dew-point in dry gas.

One of the most popular methods of natural gas dehydration is absorption process employing diethylene glycol or triethylene glycol as dehydration medium or desiccant. It is a mature process having been used for over fifty years. Triethylene glycol has emerged as the most popular chemicals in recent years due to several favorable desiccant characteristics. Those characteristics are high affinity for water vapor, non-corrosive, ease of generation, and low chemical losses. Read More

Natural Gas Dehydration using Desiccant and Sizing (Bonus Free Spreadsheet)

Rifka Aisyah 1 Comment

In this post, I want to share you about natural gas dehydration using desiccant using adsorption principle and how to size it.

In common commercial use, desiccant can be classified into three categories, which are gels (alumina or silica gels), alumina, and molecular sieves.

When used for natural gas dehydration, silica gel will give outlet dewpoints of approximately -70o to -80oF. As for alumina, outlet dewpoint is appoximately -100oF. Molecular sieves produced the lowest water dewpoints, as low as -150oF. For gas going into cryogenic processing, the only adsorbent that can obtain the required dehydration is a molecular sieve.

Table below shows characteristics of several type of desiccants [1]. Read More

Several Natural Gas Dehydration Methods and Range of Application

Rifka Aisyah 4 Comments

In almost every gas processing plant, there will be natural gas dehydration unit. Sometimes, it is called dehydration unit (DHU) or dehydrator. When, I was working in Tripatra and involving in Senoro Gas Development Project, the facilities consisted of dehydration unit as one of them.

Natural gas dehydration unit is an important facilities in onshore and offshore gas processing plant. Its function are:

  • To mitigate risk of water condensation, which leads to flow capacity issues (pipeline clogging and blocking)
  • To prevent hydrate formation or to minimize corrosion
  • To ensure smooth operation in downstream facilities. For example, gas pipeline is usually required 4-7 lb/MMSCF water content (87.2-152.6 ppm). For cryogenic unit (to produce LNG), water content in gas shall be less than 1 ppm. For CNG plant, before entering compressor unit, water content shall be reduced to maximum 3 lb/MMSCF to meet product specification.

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Natural Gas Line Sizing using General Pressure Drop Equation

Rifka Aisyah 9 Comments

Line sizing is a part of every engineering activity. Although it is not major part, line sizing is required when we prepare piping and instrumentation diagram. In this post, I want to share you how to do natural gas line sizing (actually the method is applicable for all kind of gases).

I usually use process simulator when it came to natural gas line sizing. Long time ago, I tried to size manually. But the result is not the same as from simulator. But, I tried again and yesterday I got a satisfied results.

Natural gas line sizing calculated in this post will be from manual calculation and from process simulator. API RP 14E is used as reference.

Based on API RP 14E, single-phase gas lines should be sized so that the resulting end pressure is high enough to satisfy the requirements of the next piece of equipment. So, the point is the end pressure. The velocity is also a noise problem if it exceeds 60 ft/s. However the velocity of 60 ft/s should not be interpreted as an absolute criteria. Higher velocities are acceptable when pipe routing, valve choice and placement are done to minimize or isolate noise.

API RP 14E mentioned several approach to calculate pressure drop, but in this post I will use general pressure drop equation. 

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