Absorption

In petroleum engineering and natural gas processing, absorption refers to two related but distinct phenomena. In gas processing, absorption is the mass transfer process in which a component dissolved in a gas phase is preferentially transferred into a liquid solvent that contacts the gas. In glycol dehydration, triethylene glycol (TEG) absorbs water vapor from wet natural gas in a contactor vessel, producing dry gas that meets pipeline water content specifications. In amine gas treating, monoethanolamine (MEA) or methyldiethanolamine (MDEA) absorbs hydrogen sulfide and carbon dioxide from sour gas, removing these corrosive and toxic components before the gas enters the gathering system. In materials science and drilling, absorption also describes the soaking of a fluid into the bulk of a porous solid material, as distinct from adsorption (which is the attachment of a fluid to the surface of a solid). Understanding the distinction between these two processes is important for correctly designing gas conditioning systems and for interpreting the behavior of formation-reactive fluids.

Key Takeaways

Glycol absorption for gas dehydration works on the principle that TEG has a strong affinity for water molecules: the water vapor in the gas dissolves preferentially into the liquid TEG rather than remaining in the gas phase. In a glycol contactor (a vertical vessel with packing or bubble-cap trays), wet gas enters at the bottom and rises through the vessel. Lean TEG (regenerated glycol, typically 98.5 to 99.5 percent glycol by weight) is pumped in at the top and flows downward through the packing. Water transfers from the gas to the glycol at each contact point. Gas exits the top at the required water dew point (typically -10°C for pipeline sales gas). Rich TEG (glycol that has absorbed water, now 95 to 97 percent glycol) exits the bottom and is sent to the regeneration unit (still) where it is heated to drive off the absorbed water, regenerating it for reuse.
Amine absorption of acid gases (H₂S and CO₂) uses a chemical absorption mechanism rather than physical absorption. Physical absorption (like TEG-water) depends on the solubility of the gas in the liquid solvent. Chemical absorption relies on a reversible chemical reaction between the absorbed gas and the amine: H₂S + RNH₂ → RNH₃⁺ + HS⁻. The amine reacts with the H₂S or CO₂ at low temperature in the contactor, forming a salt that is soluble in the amine solution. The rich amine (loaded with acid gases) is sent to the regeneration still, where heat reverses the reaction, releasing the acid gas and regenerating the lean amine. MDEA is preferred over MEA for selective H₂S removal (it reacts faster with H₂S than CO₂, allowing CO₂ to slip through when only H₂S removal is needed).
Absorption oil is used in older natural gas liquid (NGL) recovery plants to absorb propane, butane, and heavier hydrocarbon components from the gas stream. In an absorption oil system, a light oil (naphtha or kerosene fraction) is contacted with the gas in an absorber vessel. The heavier hydrocarbons in the gas (C₃+) dissolve preferentially into the absorption oil, while methane and ethane remain in the gas phase. The rich absorption oil is then stripped in a still, where the absorbed heavy components are flashed off and separated into LPG and natural gasoline products. Modern NGL recovery uses cryogenic expansion (more efficient) rather than absorption oil, but many older plants in Alberta and British Columbia still use absorption oil systems.
In drilling and completion engineering, absorption refers to the property of certain materials (including some shales, clays, and polymers) to soak up water into their bulk structure, causing swelling or dissolution. Water-sensitive shales absorb water from drilling fluids, causing clay platelet expansion (particularly smectite) that destabilizes the wellbore wall and generates stuck pipe and borehole washout. Inhibited drilling fluids (with KCl, glycols, or silicate salts) are formulated to minimize water absorption by the formation by suppressing the osmotic driving force for water uptake. Polyacrylamide polymers added to drilling mud act as encapsulants that prevent water uptake by clay surface sites.
The distinction between absorption and adsorption matters in several petroleum engineering contexts. Adsorption is a surface phenomenon: gas or liquid molecules attach to the surface of a solid (e.g., methane adsorbed onto the surface of coal cleats or kerogen in shale). Absorption is a bulk phenomenon: the molecule penetrates into the interior of the absorbing material. In coal bed methane (CBM), gas is stored primarily by adsorption on the coal surface rather than absorption into the coal bulk. In organic-rich shales (Duvernay, Montney, Barnett), both adsorbed and free (compressed) gas contribute to total storage, and the ratio affects desorption kinetics and long-term production profiles.

Glycol Absorption: The Most Common Gas Conditioning Step

Before natural gas can be transported in a pipeline, it must meet a water dew point specification: the temperature at which the gas starts to condense liquid water as it cools. In Alberta, pipeline gas must have a water dew point below -10°C at line pressure (most gathering systems operate at 5 to 10 MPa). Wet gas at the wellhead typically has a water content of 500 to 2,000 milligrams per standard cubic metre (mg/scm). After TEG dehydration, the water content drops below 65 mg/scm (the AER requirement for pipeline quality gas).

A TEG dehydration unit on a wellsite occupies a skid roughly 3 metres by 6 metres. It consists of a glycol contactor vessel (1 to 3 metres tall depending on gas throughput), a lean-rich heat exchanger, a still (for regeneration, fired by a small gas burner), and a glycol pump. The unit requires no operator intervention for routine operation and is controlled by a simple set of thermostats and level controllers. Lean TEG circulation rate is typically 20 to 40 litres of TEG per kilogram of water to be removed.

The single most common problem in TEG dehydration is carry-over of TEG into the outlet gas from the contactor, caused by excessive gas velocity through the vessel (glycol entrainment) or foaming inside the contactor. TEG carry-over coats downstream equipment and can cause problems at the pipeline meter run. The solution is either reducing the gas rate, adding a mist eliminator at the top of the contactor, or injecting a small amount of defoaming chemical into the TEG circulation loop.

Fast Facts

Glycol dehydration was first commercialized in the 1940s as the natural gas transmission system in North America expanded and water condensation in pipelines became a major operational problem. TEG replaced diethylene glycol (DEG) as the preferred glycol in the 1950s because TEG has a higher boiling point, which allows regeneration at higher temperatures and achieves lower water dew points than DEG. The Alberta Energy Regulator (AER) established the -10°C water dew point specification for pipeline gas in Alberta in the 1970s. In sour gas plants (which process H₂S-containing gas), glycol absorption for dehydration follows amine gas treating for H₂S and CO₂ removal, because the acid gas scrubbing process also removes some water. In British Columbia's Montney play, almost every well pad has a small glycol dehydration skid because the Montney gas is typically water-saturated at reservoir conditions.

Amine Absorption for Sour Gas Treating

Natural gas from many Western Canadian formations contains H₂S and CO₂ at concentrations that exceed pipeline specifications (Pipeline gas must contain less than 23 mg of H₂S per standard cubic metre and less than 2 percent CO₂ by volume in Alberta). Gas from the Turner Valley field (Canada's first major gas field, producing since the 1920s) typically contained 4 to 8 percent H₂S. The Jumping Pound and Caroline plants in the Foothills of Alberta process Mississippian gas with H₂S concentrations of 10 to 20 percent and CO₂ of 5 to 10 percent.

At these concentrations, amine absorption is the only practical gas treating method at commercial throughput. MDEA is the preferred amine for high-H₂S-concentration gas because its selectivity for H₂S over CO₂ reduces the amount of CO₂ that must be processed, lowering the heat requirement for regeneration. The amine contactor and regeneration still for a plant processing 5 million standard cubic metres per day of sour gas are among the largest process vessels on the plant site, with contactor heights of 20 to 30 metres and regeneration reboiler duties of 5 to 15 megawatts.

In gas processing, absorption is also called gas absorption, scrubbing, or gas conditioning. Related terms include adsorption (the attachment of gas or liquid molecules to the surface of a solid, as distinct from absorption into the solid's bulk; methane storage in coal cleats and shale organic matter involves adsorption, not absorption), glycol dehydration (the process of using triethylene glycol or other glycols to absorb water vapor from natural gas; the most common absorption process in the natural gas industry), amine treating (the process of using amine solutions to absorb H₂S and CO₂ from sour gas by chemical absorption; the standard method for sweetening sour gas before pipeline delivery), absorption oil (a light liquid hydrocarbon used to absorb heavier hydrocarbon components from a gas stream in NGL recovery plants; an older absorption-based NGL recovery technology), and contactor (the vessel in a gas absorption system where the gas and liquid solvent are brought into intimate contact to allow mass transfer; uses packing or trays to maximize the gas-liquid interface area).

How a TEG Absorption System Failure Caused a Pipeline Water Condensation Event in Alberta

A small independent operator produced natural gas from three Viking Formation wells in the Provost area of east-central Alberta, gathering the gas through a 12-kilometre pipeline to a sales meter. A glycol dehydration skid was installed at the gathering manifold to bring the gas to pipeline water dew point specification before sales metering.

During a January cold snap, the gas temperature at the contactor inlet dropped significantly because of the cold ambient temperature. The glycol circulation pump, which was not winterized, developed bearing failure and stopped circulating TEG through the contactor at 03:00 on a Saturday morning. The automatic alarm failed to notify the on-call operator because a communication system outage had taken the telemetry offline earlier that week.

By Sunday evening (approximately 42 hours later), the gas entering the sales pipeline was no longer being dehydrated. Water content rose from 35 mg/scm to over 800 mg/scm. At the cold temperatures in the buried pipeline (approximately -8°C soil temperature), water began condensing in the low points of the gathering system. By the time the operator was notified on Monday morning, approximately 1,200 litres of liquid water had accumulated in the pipeline, severely restricting gas flow and causing the three producing wells to back-pressure to near-shut-in conditions.

Restoring production required a coiled tubing unit to dewater the pipeline and repair the glycol pump, taking 4 days. Total lost production was approximately 420 Mcm (15 million cubic feet). At the gas price of the time (CAD 3.20 per GJ), the lost production value was approximately CAD 150,000. The TEG skid winterization (insulation and heat tracing) that would have prevented the pump failure cost CAD 12,000. The communication system redundancy (cellular backup for telemetry) that would have notified the operator within minutes of the pump failure cost CAD 3,500 annually.