Point 2 Point

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By:  W. G. “Trey” Brown

Abstract

There are numerous types of technologies available for the treating and conditioning of natural gas streams. Unfortunately, choosing what technology to use for a specific application can be confusing and is often times not fully evaluated to determine what option will provide the most efficient and cost effective solution. The evolution of new technologies and application of old technologies in new ways has made this decision making process even more difficult. Additionally, there are more types of gas streams that need to be treated. Whether it be Coal Bed Seam Gas, landfill gas, bio-gas from dairy farms, or natural gas from gas and oil well production, most gas produced today has one or more contaminants that need to be removed before the gas can be sold into the pipeline. In this paper we will endeavor to look at the various gas treating options available for both conventional and not so conventional gas streams and evaluate which options would be the best fit for each case, as well as the environmental impacts associated with each. This paper will also investigate the feasibility, both economically and operationally, of combining different processes to achieve the desired treating results.

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By: Gary L. Trotter & Q. Zane Rhodes II

ABSTRACT

Oso Oil & Gas Properties LLC installed a system to gather and process coal mine methane gob gas in Carbon County, Utah near the city of Price. Coal mine gob gas is methane gas diluted with various contaminants from the mine air ventilation system. The gob gas comes from the long wall cave areas of the Aberdeen Tower Mine and is brought to the surface with vertical drill holes that have been installed by the mining company to ensure mine safety. Under an exclusive agreement with Andalex Resources, Inc., the mining company that owns the Tower Mine, and the mineral estate owners, Oso collects the gob gas at the mine’s vent wells. Oso compresses the gas and removes a small amount of hydrogen sulfide then transports the remaining gas five miles to a facility where oxygen and nitrogen are removed. The oxygen removal system is based on a catalytic combustion process. This oxygen removal process allows the gathering of the gob gas at a vacuum allowing a maximum amount of gas to be recovered. The resulting gas is then transported to the Pioneer Castle Gate Field processing plant where Oso and Pioneer gas is commingled and carbon dioxide and water is removed. The combined streams are then sold to Questar at the Whitmore Park interconnect approximately twelve miles from the Castle Gate Field. This project makes economic and environmental sense by allowing the recovery of a valuable gas stream that would otherwise be vented into the atmosphere.

Rich/Lean Amine Loading – Amine loading, the amount of acid gases contained within a given amount of amine, is critical in the operation, maintenance and performance of an amine plant.

Rich Amine Loading (RAL) is determined by measuring the amount of acid gas contained in the amine stream exiting the Amine Contactor. This is typically represented in a mol ratio ((mol of CO2 + mol H2S)/mol amine). Generally speaking, this measurement is almost impossible to accurately measure in the field or in a lab, so plant simulations are often times used to determine the RAL and adjust amine circulation rates and concentrations to meet desired results. As RAL increases above a value of 0.40 mol AG/mol amine, several detrimental effects may be encountered, especially in an all CO2 acid gas system. These effects may include higher corrosion rates, higher temperature bulges within the Contactor and lower recovery of the acid gases, due to slower reaction kinetics and capacity. Thus, if the Rich Amine Loading exceeds recommended limits, acid gas breakthrough may occur, process piping may erode/corrode (resulting in piping failures) and equipment may fail. For these reasons, Newpoint recommends regular “audits” of amine plant operation, while also employing stainless steel materials in the most critical areas of the plant.

Lean Amine Loading (LAL) is determined by measuring the amount of acid gas contained in the amine stream exiting the Amine Regenerator and is measured in the same manner as the RAL described above. This is a much easier and more reliable measurement, though simulation results can still be used to check the collected data. LAL values will vary, depending on the type of amine being used. For MEA, which is one of the most corrosive amines, a LAL of up to 0.15 mol/mol may be seen, while in an MDEA system (one of the weakest and least corrosive amines) a LAL of 0.005 mol/mol is not uncommon. Lean Amine Loading will be affected by the reboiler duty, reflux ratio and the number of fractionation stages within the Amine Still. If the lean amine is not properly “stripped” of the acid gases corrosion may be encountered in the hot portions of the plant, specifically the Amine Still Reboiler and associated piping. Also, if the LAL is too high, the ability of the amine to remove the acid gases from the inlet gas stream in the Amine Contactor may be diminished and product specifications may not be met. This is especially true of MDEA systems that try to meet a very low level H2S specification.

Therefore, when designing and operating an amine plant, care should be given to making sure the system is large enough to avoid overloading the amine with acid gases (high RAL) and ensuring that the amine regenerator has sufficient capabilities to properly strip the acid gases from the amine (low LAL).

<p>Membrane systems are typically used for “bulk” removal of contaminants in natural gas streams. These contaminants are usually components such as carbon dioxide (CO2) or nitrogen (N2). Membrane systems consist of semi-permeable elements that allow specific sized gas molecules to pass through the membrane into the low pressure “permeate” stream, while retaining the majority of other gas molecules in the exiting “residue” stream. Membranes are often used in conjunction with other gas treating options to improve fuel efficiency and reduce capital outlay. An example of this would be to reduce the CO2 content of a gas stream from 40% to 10% and then treat the “residue” gas stream with amine to meet pipeline specifications. This arrangement reduces the size of the amine plant by a factor of four (4), thus reducing energy and capital. Additionally, the “permeate” gas stream from the membrane would contain enough methane gas that it could supply all fuel gas needs for the amine still reboiler/heater.<br /> Membranes are also a good alternative on small gas systems that require treating, but do not necessarily have utilities necessary to support an amine plant.</p>

Triethylene Glycol (TEG) dehydration is generally used to dehydrate a natural gas stream to pipeline specification levels of 5-7 pounds of water per million standard cubic feet of gas (lbs H2O/MMSCF). The TEG contacts the natural gas stream in a counter-flow operation with TEG being fed to the top of a trayed or packed TEG Contactor and natural gas entering at the bottom of the Contactor. As the TEG and vapor mix, the TEG absorbs water vapor from the gas stream. The amount of water removed is dependent on the amount of contact time between the TEG and gas stream. The “rich TEG” (water heavy) is regenerated, using heat to strip the water from the TEG. TEG regeneration temperatures are generally maintained at approximately 400F at near atmospheric conditions. The “lean TEG” generally has a TEG concentration of 98.5 to 99.5 weight percent (wt%). While not typically used for dewpoint depression, TEG can be injected into a natural gas stream, much the same as Ethylene Glycol (EG), for this purpose.

<p>Molecular sieve (mol sieve) dehydration is used when it is necessary to reduce the water content in natural gas to less than 1 ppmv, such as upstream of a cryogenic gas plant (cryo plant). Mol sieve is a solid bed dessicant that has tiny pores designed to absorb water vapor molecules from the natural gas stream. These pore sizes typically range from 3 to 5 angstroms in dehydration service. The arrangement of mol sieve beds can vary widely, depending on gas flow rate, inlet temperature and pressure and water content. The system is regenerated using hot, dry gas (either a portion of dehydrated inlet gas or a portion of the residue gas stream) to strip the water vapor from the mol sieve. The regeneration gas is then cooled and a portion of the water vapor is condensed and removed for disposal. Additionally, mol sieve systems can be designed to remove other contaminants, such as carbon dioxide (CO2), hydrogen sulfide (H2S) and mercaptans.</p>

Blended amines combine the best of the different amines. However, the corrosion rates are “additive”, so care should be taken on the blended strengths that are used. The “blends” are typically MDEA based and use the weak amine to do the bulk removal of the acid gases. The complimentary amine, MEA or DEA, is then used for deep removal of the remaining acid gases. The total concentration of amine in water should never exceed 50 wt% and may be somewhat lower, depending on the ratio of each amine used. A typical amine blend may consist of 10 wt% DEA and 40 wt% MDEA, or 8 wt% MEA and 37 wt% MDEA. Whatever the application, the amine blend can be adjusted to meet the specific need in the most energy and cost effective manner possible.

MDEA is a tertiary amine and forms very weak chemical bonds, at a reduced kinetic reaction rate. As such, MDEA has difficulty in obtaining total CO2 removal at any pressure less than 700 psig. However, this weak reaction capability allows the user to use MDEA to partially treat the gas stream so that pipeline specifications are met, but not remove all the CO2. This results in less amine being circulated and greater energy efficiency. Additionally, MDEA is relatively non-corrosive, compared with other amines, and its operating concentration can be maintained as high as 50 wt%. Finally, the weak chemical bonds allow for easy regeneration of the amine and significantly lower heat input into the system. MDEA should be used whenever possible to minimize amine circulation and heat requirements, but only when the acid gas specifications on the treated gas do not require total removal.

DEA is a secondary amine and not as corrosive as MEA. While the reaction kinetics between this amine and the acid gases is still strong, DEA is better utilized at operating pressures above 250 psig. Like MEA, DEA is aggressive toward all acid gases and will not “slip” any CO2 into the treated gas stream. However, its relatively lower corrosiveness allows the concentration of DEA in water to increase up to 35 wt%, though 30 wt% is most common. Since the chemical bonds are not as strong in DEA, compared with MEA, less heat input is required to regenerate this amine. Except for very low pressure applications, DEA should be used when total removal of acid gases is required.

MEA is a primary amine and has a very strong chemical reaction with the acid gases, CO2 and H2S. As such, this amine can be used in low pressure applications where total removal of the acid gases are necessary. However, because of its strong reaction with the acid gases, MEA is also very corrosive and its concentration must be limited to less than 25 wt% in water. This results in higher circulation rates to limit corrosion. It is also more difficult to regenerate the amine (to break the chemical bonds and remove the acid gases from the amine) and requires additional energy, compared to other amines. Thus, MEA should only be used in applications where the treating pressures are low and total removal of the acid gases is required.