### OPTIMIZATION OF NATURAL GAS GATHERING SYSTEMS AND

GAS PLANTS

Keith A. Bullin, P.E. Bryan Research and Engineering, Inc. Bryan, Texas, U.S.A.

Jason Chipps Bryan Research and Engineering, Inc. Bryan, Texas, U.S.A.



### ABSTRACT

Due to the increase in natural gas prices in the past few years, the benefits of optimizing natural gas gathering and proces sing systems have become substantially greater. These benefits can be observed fr om an analysis of the operating conditions, updating gas contracts, and adding gas to ex isting systems when excellent opportunities

exist. A new technique has been developed to accurately model gas processing systems to incorporate an economic simulation with the process simulation. This new technique

utilizes an Excel interface w ith process simulation software to include economic factors with the simulation results. As a result, an extended analysis of the operating conditions of the facility as well as the economic c onditions can be simultaneously combined to provide a complete model of the system. Th is methodology can be extended to include a parametric study of the available process and ec onomic variables. Excel solvers may also be used to generate the economic optimum set operating conditions.INTRODUCTION

Process simulation has been traditionally used to troubleshoot and maximize the performance of gas processing facilities. Ec onomic considerations are often performed in spreadsheets disconnected from the process simulation model. As a result, economic models cannot be easily combined with th e process model. In many instances, one person handles the day to day plant operati ons and uses the process model while the person who negotiates gas contracts uses the ec onomic model. A new technique has been developed to combine the process and economic models in a seamless format which gives economic insight to genera l process simulation problems. Once the two models are connected, process changes will be automatically

reflected in the economics. Parametric studies or solvers may be utilized to determine the overall economic picture, but it is helpful to review the important drivers for the process

and economics.

IMPORTANT FACTORS FOR GAS GATHERING AND PROCESSING

SYSTEMS

Natural gas gathering systems are a unique product of continua l changes from the addition and depletion of wells. Some gath ering systems contain spare capacity from fields which never developed. Other gather ing systems are pushing capacity constraints from fields which exceed expectations. As a result, modeling gas gathering systems is an art which can have many forms. Some of th e major factors for consideration from both a process and economic perspective are shown below:

Pressure Drop / Compressor Fuel - Increased gas density at higher pipeline operating pressures allows for more gas to travel thr ough a given line size. Higher pressure drops directly contribute to increas ed compression fuel costs.

Liquids in Pipelines - Produced gas generally enters the pipeline near its dew point. As a result, cooling of the gas through the gathering system can create liquids in the pipeline. These liquids can collect in low spots and incr ease the pressure drop th rough the pipeline. The value of the pipeline liquids may be significant. A second source of potential liquids o ccurs when the gas is compressed and cooled. These liquids present challenges because they may not be stable at atmospheric pressure, but they need to be remove d prior to a second stage of compression.

Wellhead Pressure - Many gas gathering systems require a low pressure at the wellhead to facilitate production. This can become a constraint fo r the operation of gathering

systems.

Gas Contracts - The gas gathering contracts may have many forms including fees for compression, treating, or gathering. Many gas co ntracts operate on a percent of proceeds after processing. Gas collected by gatheri ng systems may also have a mixture of ownership and contract terms.Product Prices - The sales price of ga s and liquid products is one of the most important factors in optimizing gas gathering and processing facilities. Historic price information is compiled on the Barnes and Click website 1

.

GENERAL APPROACH FOR OPTIMIZATION

Traditional methods for optimizing gas process facilities are quite complex 2

. These methods incorporate simplified pro cess calculations in order to combine economics and process simulation techniques. An example simplification is the use of

the Underwood 3 method for separation of the light and heavy key components. All other components are not considered in the distillation. Sophisticat ed numerical techniques are required to complete the process mode l such as the method proposed by Box 4

. Significant improvements in optimization ev olved with the additional capability of process simulation programs to imbed an Excel workbook or othe r spreadsheet type application. With the addition of spreadsheets in process simulation models, the general approach is quite easy; link an Excel wo rkbook to a process simulation program and transmit values back and forth. A process or pipeline facility can be modeled rigorously with the process simulation portion while the economic model can be set up in Excel. ProMax® was selected as an example for the ap plication of this tec hnique due to its ease of integration with Excel. An example of the importing and exporting feature is shown below in Figure 1. The following example illustrates this concept.

Figure 1: Importing and Exporting Values to an Imbedded Excel WorkbookOPTIMIZATION OF A NATURAL GAS GATHERING SYSTEM WITH A

PROCESSING PLANT

In many instances, the operator may in clude the gas gathering and processing under one contractual arrangement. As a re sult, the gas processing facility must be included in the overall analysis. In this example, 50 MMSCFD of 10.8 GPM gas enters an existing 20 mile pipeline at 35 psig. The gas is field compressed to achieve 100 psig at the plant gate as shown in Figure 2. Up to 25 MMSCFD of additional 7.2 GPM gas is available. The pipeline transports and pr ocesses the gas under a fixed fee arrangement ($0.25 per MCF) and the gas owner pays for the fuel. The plant inlet compression system compresse s the gas to an operating pressure of between 800-900 psig and sepa rates the methane from the heavier hydrocarbon products as shown in Figure 3. This figure also identifies several key parameters which significantly affect the oper ational efficiency and economics of the plant. These parameters are the inlet pressure, amount of inlet split for reflux to the column, the demethanizer pressure, the reboiler duty, and the chiller duty. The residue gas from the plant is recompressed to 700 psig for pipeline injection. The demethanized liquid is sold as a Y-grade product at $0.55 per gallon. Th e residue gas value is $ 5.50 per MMBTU. The plant charges small pipeline and marketing fees.

Figure 2: Gas Gathering and inlet Compression SystemFigure 3: Expander Plant with Key Operating Parameters Identified

An Excel economic model was used to repr esent the economics for the gathering and processing facility. This spreadsheet was linked to a process simulation of both the gathering a processing facility simultaneously. Table 1 lists the pa rameters residing in Excel and shared with the pro cess simulation. These paramete rs significantly affect the plant operation. Table 2 identifies the para meters calculated by the process simulation

and shared with the Excel model.

Table 1: Parameters which reside in Excel and Shared with the Process Simulation

• Plant Inlet Pressure • Percent Split for Reflux to the Top of the Column • Chiller Outlet Temperature

• Demethanizer Pressure • Reboiler Duty

Table 2: Parameters Calculated by the Process Simulation and Shared with Excel • Residue Composition and Flow • Liquid Product Composition and Flow • Compressor Energy Requirements • Reboiler and Chiller Energy Requirements

Upon completion of the linkages, various pro cess and economic factor s were investigated as shown graphically in Figures 4-9. The gross plant profit is shown in Figure 4 with variations in the reflux split. Splits from 22.5-30% yield the best results. Th ere is a small benefit to operating at an optimal value of 25%.23,500 23,750 24,000 24,250 24,500

0 5 10 15 20 25 30 35

Split for Reflux to Column (%)Gross Plant Profit ($/Day)

No New Gas

Figure 4: Plant Profit without New Gas fo r Variations in Reflux Split

The new gas stream is leaner containing 7.2 GPM compared to the 10.8 GPM existing gas stream. Figure 5 s hows ethane recovery fluctuat ions with reflux splits from 10-35%. The plant will operate at better recoveries with th e addition of the new gas.

75 80 85 90

0 10 20 30 40

Split for Reflux to Column (%)C2Recovery (%)

With 25MMSCF
New Gas

Without New Gas

Figure 5: Plant C 2 Recovery with/without New Gas

Figure 6 shows the demethanizer pressure effects on plant profitability with demethanizer pressures from 180-220 psig. The optimum for the pe rcentage of liquids scenario is the lowest demethanizer pressure . The lowest demethanizer pressure yields the greatest change in pressure throu gh the expander and generates the coldesttemperatures and best recovery. Since the plant does not have to pay for fuel in this case, the additional fuel required for recompression do es not affect the economics. If the plant is processing the new gas under a keep whole arrangement, recompression costs are important and favor operating the deme thanizer at higher pressures.

30,000 35,000 40,000 45,000 50,000

150 175 200 225 250

Demethanizer Pressure (psig)Gross Plant Profit ($/Day)

Plant Keeps 15% Liquids

Plant Processes Keep Whole

Figure 6: Demethanizer Pressure Influence on Plant Profitability

The economic response to changes in the inlet pressure is shown in Figure 7. Higher inlet pressures are optimal for keep w hole processing despite the added fuel costs

32,750 33,000 33,250 33,500

780 800 820 840 860 880 900 920

Inlet Pressure (psig)Gross Plant Profit ($/Day)

Plant Processes Keep Whole

Figure 7: Inlet Pressure Influence on Plan t Profitability w ith Keep Whole ProcessingThe inlet pressure effect on the plant profitability with a percentage of liquids contract shows a similar response to that of the keep whole contract as shown in Figure 8. Higher inlet pressures contribute to increas ed liquids recovery.

44,000 44,250 44,500 44,750 45,000

780 800 820 840 860 880 900 920

Inlet Pressure (psig)Gross Plant Profit ($/Day)

Plant Keeps 15% Liquids

Figure 8: Inlet Pressure Influence on Plant Pr ofitability with Percent of Liquids Processing

The amount of new gas was varied with di fferent contract scen arios as shown in Figure 9. The plant receives the smallest amount for processing the gas at the same $0.25 per MCF gathering and processing fee. At current price levels, the keep whole processing arrangement is only marginally better. The best scenario is to process the gas while retaining 15% of the liqui ds without charges for fuel.25,000 35,000 45,000

0 5 10 15 20 25 30

Amout New Gas (MMSCFD)Gross Plant Profit ($/Day) Plant Keeps 15% Liquids

Plant Processes Keep Whole

Fixed Gathering and Processing $0.25/MCF

Figure 9: Plant Profitability with Different Contracts for the New Gas

In summary, the technique of combini ng a process simulatio n with an Excel representation of the economi cs can be very helpful in predicting plant economic performance. This technique must be rea pplied periodically for changes in the gas, product prices, and contracts.

Literature Cited 1.) www.engineers1.com (Barnes and Click Website) 2.) Bullin, Keith A. “Economic Optimization of Natural Gas Processing Plants Including Business Aspects.” Ph.D. Di ssertation. Texas A&M University. 1999. 3.) Underwood, A. J. V. “Fractional Distill ation of Multicomponent Mixtures.” Chem. Eng. Prog., 1948, 44, 603. 4.) Box, G. E. P., Hunter, W. G., and Hunter J. S. Statistics for Experimenters . New York: Wiley Series in Probability and Mathematical Statistics, John Wiley & Sons, Inc., 1978.