Natural gas

From Active Pharmaceutical Ingredients (APIs) to Vapor Phase Corrosion Inhibitors (VCIs), any one of a thousand additives and agents can be injected into the process stream of a given industry to alter or impart new product properties or enhance processing dynamics. Injection systems and chemical skid systems offer a wide range of dosing control options. Challenge A chemical injection system typically consists of one or more chemical supply tanks or drums, a metering tank, a vessel with a mixer (if required), a variable pump, and process controls. Chemical tanks and chemical skid packages require level monitoring to ensure that the tanks do not overfill or run out of feed chemicals.

Chemical agents employed in field processing include drilling fluid additives, methanol injection for reservoir stimulation, glycol injection for hydrate inhibition, produced water treatment chemicals, foam and corrosion inhibitors, de-emulsifiers, desalting chemicals and drag reduction agents (DRAs). Chemicals are frequently administered by way of chemical injection skids. Challenge Level monitoring controls chemical inventory and determines when the tanks require filling. Though the precise measurement often comes from chemical metering pumps, it is important for the tanks not to run out or overflow.

Natural gas can travel through thousands of miles of pipeline. Compressors placed at key intervals keep the natural gas moving evenly and reliably. A typical compressor station consists of an inlet scrubber to collect liquids and slugs that may have formed in the gas pipeline. The scrubber consists of a primary section where liquids and solid parts are separated from the gas stream and a secondary section where oil mist is removed. Challenges The liquids collected from the suction scrubber are typically routed by way of scrubber level control valves to a low pressure (LP) tank. The vapors produced from the flashing liquids are vented to the atmosphere or to a flare. The low pressure condensate is periodically trucked out. Scrubbers are often equipped with high and low level alarms.

Compression station scrubbers and filters that capture liquid waste and unwanted particles route waste liquids to a storage tank. Wastes can be water condensates or heavier hydrocarbons from the natural gas. The wastes are collected in one or several tanks depending on the size of the remote station. As a waste tank fills, tank trucks are typically scheduled for tank emptying operations. As these wastes are hazardous materials, the waste holding tanks are classified as Class 1, Div. 1 areas. Challenges Measurements for both total level and interface levels between the condensed hydrocarbons and condensed water are typically made. Tank level monitoring can be provided with overflow control and alarm systems or shutdown pumps when level falls below the specified low level.

Liquid in the vent stream can extinguish the flame or cause irregular combustion and smoking. In addition, flaring liquids can generate a spray of burning chemicals— a “rain of fire”—that create a severe safety hazard. A knockout drum collects these liquids prior to entering the flare system. A level gauge and drain connections are built into the knockout drum. Challenges When a large liquid storage vessel is required and the vapor flow is high, a horizontal drum is usually more economical. Vertical separators are used when there is small liquid load, limited plot space, or where ease of level control is desired. Knockout drums are equipped with instrumentation to monitor liquid level with pump out or drain facilities. High and low level alarms are frequently installed in knockout drums.

Hydrocarbon gases are often flared in a high-temperature oxidation process which burns combustible components of waste. Environmental laws and restrictions mandate the precise monitoring of flared gases on oil and gas platforms. A flow meter is required to monitor the waste gases. Challenge Consideration must be given to abruptness of flow change, low pressures, and a wide range of velocities. Thermal dispersion flowmeters are ideal instruments for flare flow measurement due to low flow sensitivity and high turndown.

Natural gas dehydration removes hydrates which can grow as crystals and plug lines and retard the flow of gaseous hydrocarbon streams. Dehydration also reduces corrosion, eliminates foaming, and prevents problems with catalysts downstream. Natural gas is dehydrated according to the customer’s specifications for maximum water content. Challenge The most common dehydration method is the absorption of water vapor in the liquid desiccant Triethylene Glycol (TEG). The withdrawal of the water rich glycol from the bottom of the absorber is facilitated by a level control. High and low level shut down can be applied to the reboiler, surge tank and flash separator.

Natural gas separators remove solid particles and liquids from a continuous gas stream supply. Dust, dirt, sand and pipe scale as well as water, natural gas liquids and light hydrocarbons can be removed. In a typical system, an inlet separator allows particles and liquids to settle out and the gas to rise. The gas collects at the top of the separator where it is removed by means of a gas compressor. The collected particles and liquids are then dumped into a water tank. Challenge Liquid level control precisely modulates the amount of water that is drawn off to ensure that the level does not rise too high and enter the compressor inlet.

Separating the hydrocarbons and fluids from pure natural gas produces pipeline quality dry natural gas. The two principle techniques for removing Natural Gas Liquids (NGLs) are the absorption and the cryogenic expander method. The absorption method is very similar to that of dehydration except that an absorbing oil is used instead of glycol. Once NGLs have been removed from the natural gas stream, they must be separated out, or fractionated. Challenge Level control in the absorption method is typically found in flash drums, separation towers and reflux systems. Level control in the cryogenic method is applied to the separator and dehydrator.

Separators are large drums designed to separate wellstreams into their individual components. They are commonly designed to separate two-phase (gas/liquid) or three-phase (gas/crude/water) wellstreams. Separators are also classified according to horizontal or vertical configuration (see below), operating pressure, turbulent or laminar flow, and test or production separation. Challenge Interface level measurement will actuate a valve to adjust vessel level. An emulsion layer along the oil/water interface can contaminate the oil with water or the water with oil. Foaming along the gas/liquid interface, if entrained, can cause liquid carryover or gas blow-by.

Pipeline specifications require removal of the harmful acid gases carbon dioxide (CO2) and hydrogen sulfide (H2S). H2S is highly toxic and corrosive to carbon steels. CO2 is also corrosive and reduces a gas’s BTU value. Gas sweetening processes remove these acid gases and make natural gas marketable and suitable for transportation. Challenge Amine treatment removes acid gases through absorption and chemical reaction. Each of the four common amines (MEA, DEA, DGA and MDEA) offer distinct advantages in specific applications. Level control applications include reactors, separators, absorbers, scrubbers and flash tanks.

A sulfur recovery unit converts the hydrogen sulfide in the acid gas into elemental sulfur. Of the processes available for these conversions, the Claus process is by far the most well-known for recovering elemental sulfur, whereas the conventional Contact Process and the WSAProcess are the most used technologies for recovering sulfuric acid. The residual gas from the Claus process is commonly called tail gas. Tail gas is subsequently processed in a gas treating unit. Challenges The sulfur condenser vessel is equipped with a disengagement section on the outlet end in order to allow for efficient separation of the liquid sulfur from the process gas. A collection vessel equipped with continuous level control is used to store and remove the sulfur product from the process.

If allowed to escape into the atmosphere, hydrocarbon vapors diminish income through loss of hydrocarbon volume and create fire hazards and pollution problems. A Vapor Recovery Unit (VRU) collects vapors from storage and loading facilities, reliquefies the vapors and returns the liquid hydrocarbons back to storage. Methods to recover vapors include absorption, condensation, adsorption and simple cooling. Challenge A VRU is a simple, economical process unit that provides EPA compliance and improves operating economies by capturing up to 95% of fugitive emissions. Critical to the VRU is the flash drum where vapors are reliquefied. Liquid level control of the flash drum is essential.