Ref: www.dewpointcontrol.com

What is HCDP (Hydrocarbon Dew Point)Principles of HCDP | Why Control HCDP | Specifications for HCDP | Cricondentherm Temperature | Hydrocarbon Gas Dew Point Curve

Principles of Hydrocarbon Dew Point

Dew point is defined as the temperature at which vapor begins to condense. We see it in action every foggy morning. Air is cooled to its water dew point and the water starts condensing and collects into small droplets. We also see it demonstrated by a cold glass "sweating" on a humid day. The cold glass lowers the air temperature below the water dew point temperature and the water condenses on the sides of the cold glass. Water dew point is relatively simple and easy to predict since it is a single component system. It is easily removed using conventional techniques, primarily TEG (Triethylene Glycol) dehydration units.

Hydrocarbon dew point (HDP) is similar to the water dew point issue, except that we have a multi-component system. Natural gas typically contains many liquid hydrocarbon components with the heavier components found in smaller amounts than the lighter gaseous ends. It is the heaviest weight components that first condense and define the hydrocarbon dew point temperature of the gas. The dew point temperature also moves in relation to pressure.

One of the first questions we are asked by producers with a hydrocarbon dew point issue is:

"How can my hydrocarbon dew point be so high?"

In return, we ask the producer at what temperature does his high-pressure production separator operate? By definition, a production separator separating oil from gas operates at vapor-liquid equilibrium. Therefore, the gas leaving the separator is in equilibrium with the oil. In other words, the gas leaving the separator is at its hydrocarbon dew point that equals the separator operating temperature (and pressure.) If the separator is operating at 100°F, then the gas has a 100°F dew point at separator pressure. As the gas leaves the separator and cools flowing through the piping system, liquids condense and the dew point decreases as the heavy ends condense. The TEG dehydration unit will remove some heavy hydrocarbons, in addition to water, and further reduce the hydrocarbon dew point. At the sales meter, (without a conditioning unit) the hydrocarbon dew point is usually close to the lowest temperature the gas has achieved on the location before it was sampled, at operating pressure.

Why Control Hydrocarbon Dew Point?

The gas transportation companies have come to the realization that managing hydrocarbon dew point reduces system liabilities, opens up new gas markets and generates operating revenue. By managing hydrocarbon dew point, hydrocarbon condensation can be prevented in cold spots under rivers and lakes where the liquids collect in the low areas and then often move as a slug

through the system, over pressuring the pipe, and overpowering liquid handling facilities, flowing into compressors and end user sales points.

Most importantly, liquids in burners and pilots onsite and at end user locations at LDCs, can cause fire and explosion hazards. Also, removing pipeline liquids helps prevent pipe corrosion in the low areas where water is trapped under the hydrocarbon liquid layer and slowly destroys the pipe integrity. Proper managing of gas dew point can also prevent liquids from forming as the gas cools while flowing through pressure reduction stations (e.g. citygates) that feed end user supply systems. Controlling dew point is also necessary to qualify the pipeline to market gas to high efficiency gas turbine end users that require a dry and consistent quality fuel.

Specifications for HDP

Pipelines use two main methods to specify contractual natural gas hydrocarbon dew points.

1. Limit on C5+ or C6+ components by analyzing for: o GPM (gallons of liquid per thousand SCF) o Mole %

2. Specifying an actual HDP by: o Setting a hydrocarbon dew point temperature maximum at operating pressure o Setting a maximum cricondentherm hydrocarbon dew point

In addition, typical pipeline specifications, or tariffs, almost always specify a maximum GHV (Gross or Higher Heating Value), which is greatly affected by heavy hydrocarbons contained in the gas stream.

Cricondentherm Temperature

The cricondentherm temperature is the highest dew point temperature seen on a liquid-vapor curve for a specific gas composition over a range of pressure, e.g. 200-1400 psia. When you look at a hydrocarbon gas dew point temperature curve (phase envelope,) the curve bends with pressure. Shown below is a dew point curve, after conditioning, for a south Texas gas analysis. The transporting pipeline requires a 20°F cricondentherm temperature. At the time this sample was taken, the cold separator on the gas conditioning equipment was operating at 9°F and 875 psig.

Hydrocarbon Gas Dew Point Curve

The temperature shown in the HDP curve represents the gas dew point at the corresponding pressures.

A cricondentherm specification at first seems like the best way a pipeline can protect its assets. The transporting pipeline operator knows if it sets a cricondentherm temperature restriction below the lowest temperature seen in its system, it can raise and lower the gas pressure in the pipeline transportation system, and not have to worry about liquid condensation.

The problem a pipeline operator has in using a cricondentherm specification is in the calculation of the cricondentherm temperature. The cricondentherm temperature is calculated by obtaining an extended gas analysis and then inputting the analysis data into a software package, using equations of state to predict the dew point temperatures at the range of pressures.

However, many gas-transporting companies tend to collect gas composition data using on-line chromatographs or composite samples with a grouped C6+ component. The C6+ component does not provide any information on the heavier hydrocarbon (C7+) components that determine the gas hydrocarbon dew point. To calculate a cricondentherm the pipeline operator must make some assumptions. It is these assumptions that are causing problems. The pipeline operator must decide how to distribute the C6+ component for his calculation. The most commonly used distribution assumptions are the Daniels/El Paso distribution (i.e. 48% C6; 35% C7; 17% C8+) and the GPA distribution (i.e. 60% C6, 30% C7, 10% C8+). If the Daniels distribution shown in the previous sentence is used on the gas represented in the dew point curve above, the cricondentherm dew point calculates to be 38.1°F, which is 18.4°F higher than its actual cricondentherm temperature. The producer would need to operate his cold separator on his conditioning unit at -10°F (negative 10°F) to meet the system requirements due to the assumptions made in calculating the gas cricondentherm. Another popular mistake is to perform an analysis that groups the C6, C7 and C8+ components, rather than using the detailed component-by-component breakdown. Grouping also skews the cricondentherm. If you group the above components, the cricondentherm calculates at 32.6°F or 12.9°F high. It is DPC's experience that grouping will add a minimum of 3°F to 5°F to the calculated cricondentherm temperature.

Dew Point Temperature

Pressure

F PSIA9.0° 20012.9° 25015.6° 30017.5° 35018.8° 40019.5° 45019.7° 500 Cricondentherm19.6° 55019.1° 60018.2° 65017.0° 70015.4° 75013.5° 80011.1° 850 Operating at 9°F and 875#8.5° 9005.2° 9501.4° 1000-3.3° 1050-9.4° 1100-18.7° 1150

To be useful in a commercial environment, pipeline hydrocarbon dew point specifications must be easily measured with existing equipment. The majority of the transporting pipeline systems measure using a C6+ component system. These systems can be used to track cricondentherm based specifications as long as the heavier components are not distributed arbitrarily.

It is DPC is recommendation that when using a C6+ based component analysis system, the following steps should be taken to monitor a sales point location where the transporter is receiving gas that is being dew point controlled based on a cricondentherm requirement.

At time of initial delivery, when the receiving gas is meeting pipeline specification, a spot sample should be collected and analyzed with a detailed analysis through C8+.

The detailed extended analysis needs to be inputted into a software program using the full analysis to verify the cricondentherm temperature requirement is achieved.

The C6+ mole percentage (or GPM) shown on the qualifying extended analysis can then be used as the threshold standard that must be met by the gas being received at this sales meter.

Online chromatography or composite samples can then be used to compare against the threshold standard to verify qualification of the cricondentherm specification.

The threshold standard should be updated or qualified as needed to handle changing gas compositions.

DPC does not recommend detailed analysis be taken beyond C8+ on dew point conditioned gas streams as it is not useful and results in unnecessary expense.

JT UnitsJT Unit Skids | Joule-Thompson Effect | Operational Temperatures

JT Unit Skids

DPC tries to maintain an inventory of A, B, C and D size JT units.

DPC supplies four standard sizes of JT units:

Model A-JT:1 to 6 MMSCFD

Model B-JT:5 to 15 MMSCFD

click here for a larger view click here for a larger view

Model C-JT:12 to 25 MMSCFD

Model D-JT:20 to 50 MMSCFD

click here for a larger view click here for a larger view

Joule-Thompson Effect

"JT" is an abbreviation for Joule-Thompson effect. James Joule and William Thompson in 1854 proved that cooling occurs when a non-ideal gas expands from high pressure to low pressure. This cooling effect can be amplified by using the cooled gas to pre-cool the inlet gas in a gas heat exchanger. The efficiency of a JT unit is directly related to the efficiency of the gas heat exchange involved in the process.

DPC Model A JT Unit

click here for a larger view

The JT unit in the picture above consists of a gas to gas exchanger (long item), a JT valve (control or motor valve) and a two phase separator. The additional instrumentation is associated with a hot gas bypass, the pneumatic methanol pump and the methanol distribution system.

The process of expanding gas to produce cooling is not considered to be an energy efficient cooling process but can be very cost effective when "free" pressure drop or excess pressure is available. "Free" pressure drop is associated with high pressure gas reservoirs or pressure let down stations, when the pressure drop associated with the cooling effect must be taken (such as

taking a pressure drop across a choke) regardless of whether a JT unit or another process is utilized.

JT units become expensive to operate when the pressure reduction is no longer "free" and must be provided by mechanical compression. A JT unit can require anywhere from 100 psi to 800 psi differential pressure to operate. A well designed unit will minimize this pressure differential through increased use of heat exchangers and operate in the 100 to 300 psi range. The cost savings associated with the reduction of compression horsepower and compression fuel will dwarf the incremental costs to upgrade a JT unit with the extra heat exchange.

JT units have a limited application. The cooling generated from the expanded gas is limited and will only condition a gas stream that is fairly low in heavier hydrocarbon components.

DPC Model C3-JT

click here for a larger view

The C3-JT unit in the picture above uses three DPC "C" heat exchangers mounted on two skids to reduce the pressure differential across the unit. In this case, at 50 MMCFD, the savings of 200 psi in pressure differential can reduce the compression requirements by 1350 BHP or approximately $70,000/month in compression fuel ($6.50/MMBTU) and rental.

Operational Temperatures

DPC has JT units operating as warm as 60°F and as cold as -15°F.

1. Warm Operations: A warm operation is when the cold separator of a JT unit operates at anything 40°F or higher. Warm operations are usually stable as long as the unit has no greater than 7#/MMSCF of water entering it. Methanol injection is used to handle water spikes above 7#/MMSCF.

2. Cold Operations: A cold operation is when the cold separator is operating between 30°F and 20°F. To successfully operate a unit in this range, the operator must either operate his TEG system to produce 3#/MMSCF water or rely on a good methanol distribution system. 7#/MMSCF water has a water dew point of approximately 30°F at typical transporting

pipeline pressures. Therefore when operating at these temperatures with 7#/MMSCF gas, free water droplets will form. Free water will either form hydrates or freeze into ice. Without a good distribution of a suppressant like methanol, the JT unit will foul it's heat transfer surface, plug off with ice and hydrates, and ultimately stop working. The lost sales associated with only a couple hours of down time will greatly offset any savings from the rental of a JT unit from a low-quality provider. This is the major cause of downtime with JT operations.

3. Very Cold Operations: DPC defines this as any temperature below 20°F. In these cases special care must be taken. DPC highly recommends that gas water contents be lower than 2#/MMSCF for reliable operations.

METHANOL INJECTION IS ONLY A SUPPLEMENT TO GOOD DEHYDRATION OPERATIONS

Model C-JT

Click here for a larger View

Refrigeration Units

DPC leases an all electric refrigeration unit that was designed to meet the needs of the upstream production and midstream segments of the industry. These units have become very popular due to their ease of operation and installation, high turndown, and low operating costs. They have an operating range from 60° to -20°F.

B2-R (25 MMSCFD)

click here to view larger

C3-R (50 MMSCFD)

click here to view larger

The refrigeration process skid consists of a gas-to-gas heat exchanger, a gas-to-chilled water heat exchanger, a two phase separator and an electrically pumped methanol distribution and injection system. The process skid is simple and very straight-forward. Pumpers and gaugers find the unit very user-friendly, detracting little time from their routine production duties.

150 ton Chilled Water Unit

click here to view larger

DPC refrigerates the gas by circulating a chilled water and ethylene glycol mixture. The chiller unit controls process temperature by precisely controlling the circulating water temperature. Each DPC chilled water unit operates with multiple compressors and a minimum of two isolated refrigeration circuits. A PLC controls the starting and loading of the multiple compressors and condenser fans. Each compressor loads in either 1/3 increments or by sliding vane or by variable frequency drive. The system includes a hot gas bypass, variable speed condenser fans and louvers for winter operation in cold climates. At extreme low load conditions, the entire chilled water unit will shut down and then self-start as needed. The unit has built in phase and power outage protection and is set to self-start five minutes after continuous restoration of power after a clean power outage. All motor starters are included on the chilled water unit. The unit requires a single electric feeder drop with adequate over current protection.

B2-R with 50 ton Chiller (25 MMSCFD)

click here to view larger

DPC leases four standard sizes of refrigeration units:

1. A2-R: 1 to 6 MMSCFD2. B2-R: 5 to 25 MMSCFD 3. CB-R: 15 to 50 MMSCFD 4. C2-R: 15 to 70 MMSCFD

A small 5 MMSCFD refrigeration unit (A2-R) is only offered as a custom fabricated item.

Chilled water units are matched to the requirements of the refrigeration application. They all require 460 volt, three phase, 60 hertz power. The following are standard DPC sizes and require the associated electrical service size and maximum over current protection (actual power requirements are some 15% lower than the figures shown below).

30 ton 75 amps (100 KW generator)50 ton 100 amps (150 KW generator)100 ton 250 amps (250 KW generator)150 ton 350 amps (350 KW generator)250 ton 700 amps (600 KW generator)330 ton 700 amps (700 KW generator)

C3-R Refrigeration Process Skid

click here to view larger

The refrigeration process skids in the picture above has three heat exchangers. This unit was designed to handle hot gas downstream of a compressor discharge. The multiple heat exchanges reduce the chilled water unit size and lowers the overall expense of conditioning the gas stream. DPC supplies large hydrocarbon conditioning stations by operating multiple units in parallel. The picture below shows a 200 MMSCFD pipeline station.

(4) C2-R Process Skids

click here to view larger

1000+ Tons Refrigeration on a Mainline Station

click here to view larger

C2-R, Stabilization Unit in Existing NGL Facility

click here to view larger

NGL StabilizationStabilization | Process Overview | Major Equipment

Stabilization

Stabilization of natural gas liquids (NGLs) or field condensate is a process utilizing controlled flashing and in some cases, a distillation of the liquid to allow it to be stored in atmospheric vessels. The distillation of the liquid can also used to remove objectionable non-hydrocarbon components, most notably CO2, from the sales liquid.

The DPC NGL stabilization process uses tried-and-true conventional technology, employing the same modular fabrication techniques DPC uses for its standard gas conditioning equipment, allowing for high levels of quality control. All of the equipment and piping is designed, fabricated and tested per ASME and TEMA codes and standards. The system is all electric, minimizing permitting issues and reducing the hazards associated with direct fired equipment in an oil field production environment.

Stabilization Unit, CB-R Process Skid

click here to view larger

Process Overview

The equipment used in the DPC stabilizer process simply provides a way to "cook" the volatile hydrocarbons liquid mix, at the optimum pressure (50 to 350 psig) and the required temperature levels (100°F to 400°F). This is done in a distillation tower, controlled in such a way as to drive off the light gaseous hydrocarbons and other gaseous contaminants to be used as a fuel stream or recycled through the conditioning equipment, eventually to be sold as part of the pipeline quality natural gas. The resulting "stabilized" liquid thereby has a much-reduced volatility.

Stabilization Unit

click here to view larger

In many cases the liquid can be stabilized to a point that it can be stored and transported in non-pressurized vessels (crude tankers,) both enhancing safety in handling, and improving the liquid's marketability. This liquid can be marketed as a crude or "dead" condensate. In other instances, our clients may want to limit the amount of vapor driven off from the liquid, and sell a "moderately" pressurized product to an available market. Meeting a MAPCO “Y-Grade” NGL pipeline specification is a typical application. This choice only requires an adjustment in operating temperature and pressure of the stabilization unit.

Major Equipment

DPC has designed a standard unit to stabilize a nominal 500 BPD of NGL production to 9# Reid vapor pressure (RVP), with an easily operated system in a very energy efficient manner. The heat source is an electric resistance process type immersion heater, procured along with its control system, from an "old-line" process heater manufacturer. The electric heat allows for a simple installation, a stable and safe operation and avoids producing any air emissions associated with direct-fired equipment.

The maximum allowable operating design pressure (up to 1000 psig) and temperature ratings (650°F) of the system components are far in excess of the anticipated operating conditions. In

other words the equipment is over-designed and under-stressed in operation. This is deliberately done for enhanced safety and durability.

The stabilizer is a top feed quench, center heated feed tower design. Bubble cap trays are used to give the tower a stable operation over a wide range of flow conditions. The stabilizer tower has both top and middle tray liquid feed points. Multiple heat exchangers are used to recover the heat from the stabilized hot bottom product and return the energy to the middle feed tray for maximum energy conservation and product cooling.

The stabilization system is built on two process skids. The tower is mounted on a stand-up skid that then bolts to the heat exchanger and control skid for a quick and simple installation. The skids are designed to be set on stabilized ground. Concrete foundations are not typically required.

Some fabrication pictures of a stabilization unit:

Stand-up Distillation Tower after application of insulation

click here to view larger

Exchanger and Control Skid after application of insulation

click here to view larger

Pre-piping Unit Set-up

click here to view larger

Client List

Apache Corporation Agave Energy Corp Anadarko Petroleum Corporation Ballard Exploration Bass Enterprises Production Company BEPCO, L.P. BEUSA Cabot Oil & Gas Corporation CasTex Energy Chesapeake Operating, Inc. Choice Exploration Cimarex Energy Co. CML Exploration ConocoPhillips Continental Resources, Inc. DCP Midstream Partners, L.P. Denbury Onshore Edge Petroleum Enbridge Pipelines (East Texas) L.P. EnCana Oil & Gas (USA), Inc. English Bay Pipeline, L.P. Energy Transfer Company Enterprise Products Operating, LLC EOG ExxonMobil

Fairplay Energy Fairways Energy Fidelity Exploration & Production Co. Goodrich Petroleum Great Lakes Energy Partners, L.L.C. James Whitson, Jr. Ken-Tex Energy Corporation Kinder Morgan Tejas Pipeline, L.P. M2 Midstream MarkWest Pinnacle, L.P. Merit Energy Company Millennium Midstream Energy, L.L.C. Miller Dyer & Co. L.L.C. MME Midstream, L.P. Neumin Production Company Noble Energy Odyssey Petroleum Corporation ORX Resources, Inc. Patara Oil and Gas Patterson Petroleum L.P. Peak Wyoming Acquisitions, L.L.C Questar Gas Management Company Questar Pipeline Company Questar Transportation Services Company Range Operating Texas, L.L.C. Resaca Resources Samson Resources Sandalwood St. Mary Land & Exploration Company Summit Gas Talco Midstream Assets, Ltd /Winchester Texas Gas Sales, L.L.C. Toledo Gas Gathering, L.L.C. Williams XTO Energy