dehydrate, Oil & Gas Glossary

What Does Dehydrate Mean in Oil and Gas?

To dehydrate in oil and gas processing means to remove water vapour from natural gas or liquid hydrocarbon streams to levels below which hydrate formation, corrosion, or pipeline transmission specification limits would be exceeded, using processes that include glycol absorption (TEG dehydration), molecular sieve adsorption, refrigeration/cooling, or desiccant drying, with the water content of the treated gas typically reduced from saturation levels of 500-1,500 mg/Sm³ to pipeline specification targets of 48-112 mg/Sm³ (2-7 lb/MMscf) or to LNG feed gas targets below 1 ppm by volume.

Key Takeaways

Natural gas from the reservoir is saturated with water vapour at reservoir temperature and pressure; as gas cools and depressurises in the gathering system, liquid water and gas hydrates can form, plugging lines and equipment.
Triethylene glycol (TEG) absorption is the most common dehydration method for field gas processing: wet gas contacts lean TEG in an absorber, water transfers to the glycol, and the rich TEG is regenerated by heating.
Molecular sieve dehydration achieves very low water dew points (below -70°C) required for LNG liquefaction and cryogenic NGL extraction; TEG cannot achieve these ultra-dry specifications.
Gas hydrates form when free water contacts natural gas at high pressure and low temperature, creating solid ice-like plugs; prevention by dehydration or methanol injection is essential for transmission pipeline integrity.
The water dew point specification is the key process target: pipeline gas in Canada and the US must typically achieve a dew point of -10°C to -20°C at pipeline operating pressure to prevent liquid dropout in the line.

The TEG Dehydration Process

Triethylene glycol (TEG) absorption is the dominant dehydration technology for field gas processing facilities, pipeline gas dehydration, and midstream plants handling well head production at moderate flow rates. In a TEG unit, wet gas enters the bottom of a contactors column (typically a trayed or packed absorber vessel) and flows upward countercurrently to lean TEG (>99% TEG, <1% water) flowing downward from the top. TEG is highly hygroscopic — it absorbs water molecules from the gas phase because its equilibrium water vapour pressure is extremely low. As the gas rises through the contactor, water transfers from the gas to the TEG phase until the exit gas achieves the target dew point. Rich TEG (typically 95-97% TEG, 3-5% water) exits the bottom of the contactor and is routed to the regeneration system.

TEG regeneration involves heating the rich glycol in a reboiler to approximately 190-205°C (below TEG's decomposition temperature of approximately 206°C) to evaporate and drive off the absorbed water as steam, restoring the TEG to a lean concentration above 99% (measured as TEG purity, which is the weight percent of TEG in the water-TEG mixture). The steam and light hydrocarbons evaporated during regeneration are typically flared or routed to a vapour recovery unit to capture the glycol vapour losses and meet environmental emission limits on VOC and BTEX emissions from the glycol regenerator vent. Lean TEG is cooled (glycol-glycol heat exchange and air cooler) and recirculated to the top of the contactor. The regeneration achieves TEG concentrations of 98.5-99.5% with a standard firetube reboiler, or up to 99.95% with Stahl column (stripping gas) enhancement that sweeps the regenerator vapour space with a dry hydrocarbon gas or nitrogen stream to lower the partial pressure of water vapour and drive the regeneration closer to completion.

Dehydration Applications Across International Jurisdictions

In Canada, natural gas dehydration is required at virtually all WCSB gas gathering and processing facilities before gas enters the Alberta Gas Transmission (NOVA) or TC Energy pipeline system. AER Directive 017 (Measurement Requirements for Oil and Gas Operations) and the Natural Gas Pipeline Act specify the water content specifications that gathering system gas must meet; standard AGTL/NOVA Gas specification requires water content below 64 mg/Sm³ (4 lb/MMscf) and a water dew point below -10°C at maximum operating pressure. Montney and Duvernay deep basin gas wells produce gas saturated with water at high reservoir temperatures; the dehydration requirement begins at the wellhead separator and continues through the gathering system to the plant inlet. For LNG projects such as LNG Canada (Shell, Petronas, PetroChina) in Kitimat, BC, the feed gas undergoes ultra-deep dehydration to below 1 ppm water using molecular sieve beds before liquefaction at -162°C, where even trace water would freeze and plug the heat exchanger channels.

In the United States, interstate natural gas pipeline tariff specifications typically require water content below 112 mg/Sm³ (7 lb/MMscf) and dew point below the operating temperature of the pipe — the specific value varies by pipe segment temperature in winter operation in northern states. FERC pipeline operating standards incorporate these water specifications into approved tariffs. Permian Basin gathering systems handling casinghead gas from oil wells require dehydration before the gas is accepted into the gathering pipeline; the gathering company's contract specifications define the water dew point requirement at the delivery point. Gulf of Mexico offshore production platforms operate compact TEG units to dehydrate gas before it enters the subsea or platform-to-shore export pipelines. In Norway, Equinor's Troll and Åsgard gas processing platforms include TEG dehydration as part of the gas conditioning train before gas enters the Europipe and Åsgard Transport pipelines to Germany and the UK. In the Middle East, Saudi Aramco's Master Gas System (MGS) processing plants include TEG dehydration units to condition Arab Formation gas before pipeline distribution to industrial users and power generation plants across the Kingdom.

Fast Facts

The equilibrium water content of natural gas at typical wellhead conditions (70°C, 10 MPa) is approximately 1,500-2,000 mg/Sm³ — 30-40 times the standard pipeline specification of 64 mg/Sm³. A 100 MMscfd gas production facility therefore needs to remove approximately 1,400-1,900 kg of water per million standard cubic metres of gas processed, totalling 140-190 tonnes per day of water removal. This water, recovered as hot condensate from the TEG regenerator, is typically disposed of by evaporation in a disposal pit or by injection into an appropriate disposal formation — it contains dissolved TEG, heavy hydrocarbons, and possibly H2S that require proper management under environmental regulations.

Molecular Sieve Dehydration for Ultra-Low Water Content

Where TEG dehydration cannot achieve the required water dew point — below approximately -30°C to -40°C at pipeline pressure — molecular sieve (zeolite) adsorption is used. Molecular sieves are synthetic crystalline aluminosilicates with precisely sized pore openings (3 Angstrom or 4 Angstrom for water removal) that selectively adsorb water molecules while excluding hydrocarbon molecules. Gas flows through a fixed bed of molecular sieve adsorbent; water molecules enter the sieve pores and are retained while the dried gas exits. When the bed approaches saturation, flow is switched to a parallel regenerated bed while the saturated bed is regenerated by passing hot (260-320°C) dry gas through it to desorb and remove the adsorbed water. The regenerated bed is cooled and returned to adsorption service in a cyclic process. Molecular sieves can achieve water content below 1 ppm by volume (equivalent to dew points below -100°C), meeting the requirements for LNG feed gas, cryogenic NGL extraction (dewpoint below -60°C required to prevent hydrate formation in the cold box), and some high-specification instrument gas applications.

Tip: When troubleshooting a TEG dehydration unit that is failing to meet dew point specification despite normal glycol circulation rate and regeneration temperature, check the glycol concentration before adding more lean glycol to the system. A common root cause is that TEG purity has declined over time due to contamination — hydrocarbons co-absorbed in the absorber dissolve in the glycol and cannot be stripped at normal regeneration temperatures, degrading the glycol's water absorption capacity. Pull a representative lean TEG sample and send it to a laboratory for TEG purity, pH, and hydrocarbon analysis. If TEG purity has dropped below 98.5% and hydrocarbon content is elevated, the glycol needs to be filtered, distilled, or replaced rather than simply continuing to add more degraded glycol. Running a Stahl column (stripping gas) on the regenerator or increasing the reboiler temperature within the design limit are the first operational interventions before committing to glycol replacement.

Dehydrate in oil and gas is also referenced as:

Dry — the informal operational term for the process and the product; "drying the gas" is synonymous with dehydrating; "dry gas" is gas that has met the water specification (as distinct from a thermodynamically dry gas with no condensable hydrocarbons)
Water removal — the engineering description of the dehydration function when discussing process design; "water removal duty" refers to the required kg/hr or lb/hr of water that the dehydration unit must remove from the gas stream
Gas conditioning — the broader term for all processing steps that bring wellhead gas to sales gas specification, of which dehydration is one component; others include gas sweetening (H2S and CO2 removal), hydrocarbon dew point control (NGL extraction), and compression

Frequently Asked Questions

What is the difference between water dew point and hydrocarbon dew point in gas specifications?

Water dew point and hydrocarbon dew point are separate specifications that address different condensation phenomena in natural gas pipelines. The water dew point is the temperature at which water vapour in the gas stream begins to condense to liquid water (at the prevailing pressure). Exceeding the water dew point causes free water in the pipeline, leading to hydrate formation, corrosion, and slug flow — hence the pipeline specification requires the gas water dew point to be well below the minimum operating temperature of the pipe. The hydrocarbon dew point is the temperature at which the heaviest hydrocarbon components (pentane, hexane, heptane, and heavier) in the gas stream begin to condense to liquid hydrocarbons. Exceeding the hydrocarbon dew point causes liquid hydrocarbon dropout in the pipeline, affecting gas measurement accuracy, increasing pipeline pressure drop, and potentially causing compressor liquid slugging. Hydrocarbon dew point control requires removal of heavy hydrocarbons (C5+) from the gas at the processing plant, typically by refrigeration or lean oil absorption — a separate process from the water dehydration that meets the water dew point specification. Both specifications must be met simultaneously for a gas to be accepted into a transmission pipeline.

How does H2S content affect TEG dehydration performance?

H2S in the feed gas to a TEG dehydration unit has several interactions with the glycol system. H2S is partially absorbed by the TEG in the contactor — it has moderate solubility in glycol and will be partially stripped in the regenerator and released in the regenerator vent gas (which typically contains water vapour, light hydrocarbons, and absorbed acid gases from the regeneration step). This H2S in the vent gas creates a toxic emission stream that must be handled safely — either incinerated in an enclosed flare or scrubbed with a caustic solution before atmospheric discharge. H2S also reacts with iron contaminants in the glycol system to form iron sulphide (FeS) particulates that cause fouling of regenerator tubes, filter plugging, and reduced glycol purity over time. Acid gas absorption in the glycol lowers the pH of the rich glycol solution, increasing the corrosion rate of carbon steel equipment. TEG dehydration units processing sour gas require upgraded materials (stainless steel regenerator internals, corrosion inhibitor injection), more frequent glycol reclaiming to remove degradation products, and H2S safety monitoring and handling procedures that differ substantially from sweet gas operation.