Energy Blog

Field optimization using IHS Piper – Part II: Cost cutting by shutting-in wells




This article reviews features available in IHS Piper that can be used to test cost cutting for hydrocarbon gathering systems by shutting-in wells. General field optimization ideas and workflows are reviewed in a previous blog titled “Field Optimization Using IHS Piper – Part I: Optimizing Gathering Systems”. You may want to visit that earlier post prior to reviewing this one.

Shutting-in wells will reduce operating costs, and may alleviate pipeline capacity issues, but it will also reduce total field production. The result may have positive impact on expenditures and operational issues but have a negative impact on revenues. Both positive and negative impacts should be considered when deciding if a scenario should be pursued.

In Figure 1 the Base Case is shown, and Figure 2 shows a scenario with two well pads shut-in. A frictional pressure loss map for the pipelines is displayed on the map view.

Figure 1: Base case model of gathering system. Note frictional pressure loss map legend in top right corner. The orange arrow indicates a trunk line with moderate frictional pressure losses.

Figure 2: Well shut-in scenario of the same gathering system shown in Figure 1. Note frictional pressure loss map legend in top right corner. The orange arrow indicates a trunk line with reduced frictional pressure losses. Grey bubbles surround wells that were shut-in for this scenario.

 

The diagnostic frictional pressure loss map shows that the scenario of shut-in wells reduces frictional pressure in one trunk line. You can also compare total field production for the base case and scenario. Figure 3 shows total production rates for the Base Case and Figure 4 shows total production rates for the scenario with shut-in wells. 

Figure 3: Delivery rates for a 12 month forecast for the gathering system Base Case. April 2015 the total rate is ~750 103m3/d, and at the end of the 12 months it has declined to ~650 103m3/d.

Figure 4: Delivery rates for a 12 month forecast for the well shut-in scenario. April 2015 the total rate is ~700 103m3/d, and at the end of the 12 months it has declined to ~615 103m3/d. Total delivery rates are approximately 6% less than the base case.

 

Total field production in the scenario with shut-in wells is lower than the Base Case, which is expected. If you have a delivery contract to meet, you will want to check the total field production with shut-in wells to make sure the field can still meet that contract, and if not, how far short of the contract you might be. Check the forecasted field production over time to determine on which date you fall short of delivery commitments and consider bringing wells online to mitigate. You can also create another scenario where shut-in wells are put back on production.

Before deciding if the scenario of shutting-in wells should be pursued, you will also want to know how much operating expenses will be reduced compared to the Base Case. The economics feature in IHS Piper can be used to make a Net Present Value report and Cash Flow report. These reports are available both for the field as well as by facility. 

Shutting-in wells may have other negative operational impacts. Compressors may not need to run at full capacity to maintain production due to decreased overall rates. If you have multiple compressor units operating in parallel service, you may be able to take one compressor off line, decommission it, or move it to another location without impacting wells that are still on production. For a different approach to the same problem, you could deactivate one compressor first, and then determine how many wells to shut-in at the beginning of the forecast; then, as time progresses you could gradually bring wells back online to ensure maximum usage at that compressor bank.

After you have considered what impact changes to the field might have, compare model results between the Base Case and alternate scenarios to determine the best option. We recommend you use diagnostic maps to quickly identify areas of concern. In the case of shutting-in wells, you might want to consider:

  • Does reducing field production have a noticeable effect on frictional pressure losses in the pipelines? If so, will wellhead pressures also drop, thereby increasing drawdown on those wells?
  • Are there areas with low gas velocity where liquids may stagnate? If so, should you consider closing some pipeline loops to keep fluid velocities high enough to sweep liquids?
  • With reduced field production, can compression capacity be reduced without adverse effects?

Finally, you may want to test how short term cost cutting through shutting-in wells impacts longer term field revenues. Hydrocarbons left in place for the short term may have higher value if produced at a later date when commodity prices have increased. Use the price deck in the economics feature to change the commodity price over time and run a future forecast and net present value report to compare revenues if production is delayed. 

Figure 5: Gas price deck feature in IHS Piper.

Depending upon how long you want to reduce expenditures, delaying production might yield the most profitable result in the longer term. Consider creating a modified well shut-in scenario where commodity prices increase in two years. Make sure your field production meets the minimum contracted rates over that time.Then change the commodity price at the two year mark and forecast for another three years. How does the total revenue generated by your field in this scenario compare to the Base Case over five years?

Your findings may indicate that additional scenarios need testing, or that the current gathering system state is the best configuration for current market conditions. If you use diagnostic maps, production rates and economic indicators for your models, your decisions will be based upon quantifiable data. 

Use the economics feature in IHS Piper to evaluate changes in operational spending, and the impact of changing commodities prices. Total field rates can be helpful to evaluate how field production will be affected by alternate field scenarios both immediately and in the longer term.

While cutting costs is one way to maintain profitability, another is to increase revenues. The blog article “Field Optimization Using IHS Piper – Part III: Optimizing Compression to Increase Revenue” will discuss how to investigate compression placement and capacity to optimize field production, and as a result increase revenues. The economics feature in IHS Piper can be used to evaluate if the increased compression expenditures are offset enough by increased revenues to be a viable field development plan.

For Further Reference:

http://blog.ihs.com/rpe-a-recipe-for-reliable-gathering-system-modeling
https://www.ihs.com/products/oil-gas-training-videos.html

One Petro – SPE No. 75946 “Case Study: Including the Effects of Stagnant Water in Gas Gathering System Modeling” by James Young, Ralph McNeil, Jeffery Knibbs

“An Effective Method for Modeling Non-Moving Stagnant Liquid Columns in Gas Gathering Systems” by R.G. McNeil, D.R. Lillico

Tracy Brenner, Principal Analyst/Researcher, IHS Markit Engineering