Process Design

  • Natural Gas Processing Plant - Fractionation and NGL Recovery - Photo courtesy of Williams Companies Incorporated, Tulsa Oklahoma

    • REM Pipeline Consultant's, Jim W. Best, is well versed in gas processing design and operations. His expertise includes a patent for H2S removal from high CO2 gas streams, fractionation design of CO2 from methane, ethane, and propane plus, and over five (5) years of direct Operations Management of gas processing plants. For our Oil & Gas industry customers, Jim can economically evaluate and design new gas processing opportunities and/or optimize an existing gas processing plant using ProMax, by Bryan Research & Engineering.

      Optimization projects normally start with the process design engineer, operating manager, or maintenance manager. Optimization projects should be structured to have well defined milestones and should have a project sponsor (Operations Manager) to ensure the management and control of ongoing activities. The optimization project effort should also include a multi-disciplinary team of personnel, all with the same goal. Typical optimization project phases are: 

        • Data acquisition
        • Maintenance costs
        • Operating costs
        • Gas savings and revenue enhancement
        • Process simulation & modeling
        • Process analyses
        • Economic analysis
        • Operating personnel buy-in to new operating conditions or equipment

        Once a project is initiated and the goal of the project set, the following optimization steps normally occur:

        • Compilation and determination of plant design data and process values
        • Comparison plant design data vs. plant operation data
        • Basic mass and energy balances
        • Process simulation modeling of the relevant systems and processes
        • Verify simulation results against real operation
        • Analysis of process values and comparison with simulation results
        • Validation of process values
        • Benchmarking: determination of plant and unit efficiencies and process benchmarks
        • Weak point analyses
        • Localization and identification of equipment malfunctions
        • Determination of Optimal plant operation points
        • Development of Optimized system operating procedures and conditions
        • Optimized control instrumentation and/or automation configuration and equipment retrofit concepts or equipment upgrades for reliability

      Design of new natural gas processing plants, NGPP, is somewhat different than optimizing existing gas processing plants. NGPP design to process raw natural gas from different oil and gas reservoirs is totally dependent on the gas composition from the reservoir. In Afghanistan, current gas production is from hydrocarbon dry reservoirs that are either sweet or sour. From the Khoja Gorgodak gas reservoir, the gas is sweet and requires only dehydration and compression to get it to a gas sales market. The Yayimtaq reservoir gas is also hydrocarbon dry, but it is also sour containing 1500 ppm of H2S. Thus a gas sweetening system is required to remove the H2S and CO2 to make the sour gas into a sweet gas before the gas is dehydrated and compressed. However, when a heavier hydrocarbon gas is to be processed such as an associated gas from an oil reservoir or gas from a gas condensate reservoir,  more gas processing equipment is required and a full fledged Natural Gas Processing Plant is required. The processing equipment required is fractionation and NGL recovery along with NGL storage and pipeline, truck or rail transportation. The additional processing makes the a dry residue or fuel gas and liquid propane, butane, and natural gasoline. Below are the typical gas compositions of the different gases mentioned. 

        • NGPP fractionation trains are composed of different but similar types of Fractionators. The number and type of fractionators required depends on the number of NGL products to be made and the reservoir gas or gas feed composition. Typical NGL products from a fractionation process include:
          • Demethanized Product (C2+)
          • Deethanized Product (C3+)
          • Ethane/Propane mixtures (EP)
          • Commercial Propane
          • Propane/Butane mixture (LPG)
          • Butane(s)
          • Butane/Gasoline mixtures
          • Natural Gasoline
          • NGL mixtures with a vapor pressure specification

      • An example fractionation train used to produce three liquid NGL products is illustrated above. The feed stream contains too much ethane to be included in the liquid products; thus, the first column is a deethanizer. The overhead stream is recycled to the upstream gas processing plant or sent to the fuel system and gas sales. The bottom product from this deethanizer column could be marketed as a deethanized liquid NGL product and pipelined to another larger NGL recovery plant. The second column, a depropanizer, produces a specification propane product overhead. The bottom product, a butane-gasoline mixture, is often sold to a pipeline without further processing. However, to produce butane and gasoline products, a third column the debutanizer is required. A debutanizer separates the iso-butane and normal butane from the natural gasoline or pentane plus product. This separation is controlled to limit the vapor pressure of the natural gasoline. The overhead butane product can be sold as a mixture or an additional column can be used to separate the iso-butane and normal- butane.
      • The chart above shows the composition of a raw gas or associated gas from an oil reservoir and where the different hydrocarbon components are sent in a fractionation process at the NGPP. NGPP plants can be built  to process various gas inlet rates, from as little as 3-5 MMscfd to 500 MMscfd. There is a big incentive in capital cost reduction to build large capacity NGPPs that process gas from many different oil and gas producing and operating companies. In the USA, gas processing hubs have been built and operators have created JV companies to achieve the economy of scale.
    Below is a typical pipeline quality gas specification which NGPPs normally meet. The gas of this quality can be used for many industrial purposes, most notably for electrical power generation to reduce imported diesel and its environmental emissions.


      • A typical commercial propane specification is
        • GaugeVapor Pressure at 104°F (40°C)
        • Vapor Pressure Maximum = 225 psig (15.5 barg, 1551 kPa)
      • A typical commercial butane specification is
        • GaugeVapor Pressure at 104°F (40°C)
        • Vapor Pressure Maximum = 75 psig (5.2 barg, 517 kPa)
      • Reference: GPSA Engineering Data Book
    • Acid Gas or Sour Gas Re-Injection
      • Reference - “Design Considerations for Acid Gas Injection” by John Carroll and James Maddocks of Gas Liquids Engieering ltd. Calgary, Alberta, Canada presented at the Laurance Reid Gas Conditioning Conference, Norman, Oklahoma, USA, February 1999. Below is a process flow diagram for acid gas injection based on this article.

    Acid gas reinjection involves handling high-pressure gas with a high concentration of hydrogen sulfide, H2S, along with carbon dioxide, CO2. This can lead to an increased safety risk if the correct materials are not selected at the compression facility design stage and requires an intense focus on achieving injection well mechanical integrity. Engineering companies that design these facilities should have real world experience in all aspects of design and operations.

    Acid Gas injection is becoming more prevalent around the world due to growing environmental concerns and government/banking regulations and requirements. Disposal of small quantities and large quantities of acid gas is a problem. In the past, oil and gas producers could flare the acid gas. New and stricter environmental regulations are curbing the disposal of sulfur compounds, sulfur dioxide-SO2, to the atmosphere. Usually an expensive sulfur plant with tail gas clean-up is required to meet environmental regulations. A typical Claus sulfur plant with three beds can achieve 95% to 97% recovery of sulfur. Adding a CBA, cold bed adsorption, to the end of the process increases recovers to 99.5%. Then, incineration is required to convert the remaining H2S by burning with additional fuel gas to SO2.

    Acid Gas injection is quickly becoming the method of choice for disposing of the sour gas stream. The sour gas is compressed and sent to a sour gas injection well drilled to a non-producing reservoir formation or depleted gas or oil reservoir. The goal here is to permanently dispose of the acid gas.

    Since the acid gas is high in CO2, the gas could be used in a miscible flood, EOR, scheme to increase oil production in an oil producing reservoir. Reservoir models should determine the gas composition over time to determine the above ground gas treating plant design. The gas to be processed will increase in gas volume and in CO2 and H2S concentration over time. The amine systems and re-injection compression should be designed for this increase in gas rate and acid gas concentration.

      Acid gas injection involves taking the acid gas from the amine regeneration system, compressing it to a sufficient pressure, and injecting the gas into a suitable underground reservoir rock formation. Acid gas injection becomes a near zero-emission process. During normal operation, all of the H2S from the produced gas in re-injected. Only during upsets will emissions occur, such as acid gas sent to the flare. There are three basic components to the acid gas injection scheme.

      • Compression
      • Pipeline
      • Injection well
      Compression facility design should consider and design for the following
          • Water content of the acid gas which is high
          • Corrosion of piping and equipment at high temperatures and high pressure. Stainless steel materials are recommended downstream of the  first stage of compression.
          • Sour water from interstage compression scrubbers as water is condensed out of the acid gas stream as the pressure increases. Sour should then also be injected into a reservoir rock similar to the gas stream.
          • Hydrate formation in the injection line requiring methanol injection to inhibit hydrate formation.
        • Compressor design
          • Typically 4 stages of compression - compression HP and temperature rise should be considered with the CO2 and H2S
          • Materials for cylinders and rods
          • Air cooler metallurgy and sizing due to water and CO2 condensation
          • Compressor speed control to respond acid gas volume changes
          • Compressed gas recycle
          • Fuel gas should not be used in the compression system for volume control as the light HCs and nitrogen affect the required injection pressure. Actual injection can stop as the gas head in the well tubing becomes lighter and then the bottom hole pressure can not be overcome. The only way to overcome this is to increase the wellhead injection pressure. Gas injection temperature also can also make the gas head lighter, thus causing the same problem.  
        • Pipeline Design
          • Keep pipeline as short as possible if possible
          • Use 304/316L stainless steel
          • Externally coat the pipeline
          • Bury pipeline at 6 foot depth to use ground temperature to prevent gas hydrates from forming
          • Redundant instrumentation
        • Safety Issues Identified and Mitigated
          • Insure mechanical integrity of entire mechanical and instrumentation systems - use redundancy
          •  Use ESDV, emergency shutdown valves for compression and wellhead
          • Overly tall emergency flare with 4 pilots and more than adequate fuel gas for burning. Focus on complete combustion of H2S.
          • Continuously monitor ambient air H2S concentrations
          • Installation should include multiple blowdowns, blowbacks, and sweet natural gas purges

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