SPE Cyclic Shut in Eliminates Liquid Loading in Gas Wells

Transcription

1 SPE Cyclic Shut in Eliminates Liquid Loading in Gas Wells Curtis Hays Whitson, SPE, NTNU/PERA Silvya Dewi Rahmawati, SPE, NTNU Aleksander Juell, SPE, NTNU 1

2 Historical Note Parametric Pulsing introduced by Tek, et al. in Not referenced in paper improper literature search. Similar to Cyclic Shut In. Not applied to liquid loading problem. Incorrectly concluded that parametric pulsing can recover gas faster than continuous production. Several papers showed this conclusion was wrong. Parametric Pulsing idea died in We formally apologize for not referencing Tek, et al. 2

3 Cyclic Shut In Control Never let the well produce at a rate below the minimum rate required to lift liquids. Shut in the well as soon as the well s rate reaches the minimum rate to lift. Reopen the well shortly (~1 hr) after the shut in. Continue indefinitely. 3

4 Liquid Loading Condensed or free water, condensate, and/or oil flow counter current to gas. Accumulated liquid loads the well and increases backpressure on formation. Minimum rate to lift Turner et al. (1969) 4 Droplet force balance. Alternative models suggest film flow reversal is main cause of liquid loading.

5 Liquid Loaded Gas Well Performance 1000 Monthly Average Gas Rate, Mscf/D 100 Meta-Stable Rate Liquid-Loading Rate Year 5

6 Model Verification SENSOR Single Well Simulator Models Vertical Well Model Permeability range: md. Thickness: 15 ft. Drainage area: 320 acres. Economic rate: 10 Mscf/D. Horizontal Well Model Horizontal multi fractured (HMF) well model with 10 fractures. Symmetry element. Permeability range: md. Thickness: 100 ft. Drainage area: 11.5 acres/fracture. Economic rate: 20 Mscf/D. Bottom hole pressure control: 10 bara. 6

7 Onset of Liquid Loading Time to Onset of Liquid Loading, days Horizontal Multi Fractured Well Vertical Stimulated Well Permeability, md 7

8 Model Control Scenarios 1. Continuously Unloaded. The gas well produces miraculously at constant BHP throughout life dry well production performance. 2. Liquid Loaded. The gas well reaches the liquid loading gas rate and the model changes the target rate to a lower constant meta stable gas rate. 3. Cyclic Shut In. The well is shut in as soon as the liquid loading rate is reached. Each shut in period is short and has the same duration. 8

9 Ultimate Gas Recovery vs Permeability Vertical 100 stimulated well 90 Ultimate Gas Recovery Factor, % Cyclic Shut In Period = 1 days Economic Rate = 10 Mscf/D Maximum Well Life = 50 Years Continuously Unloaded Cyclic Shut in Control Liquid Loading Start of Liquid Loading Permeability, md 9 Vertical Well

10 Little Delay in Recovery Vertical stimulated well 10 Vertical Well

11 Ultimate Gas Recovery vs Permeability Horizontal 100 Multi Fractured well 90 Ultimate Gas Recovery Factor, % Cyclic Shut In Period = 1 days Economic Rate = 20 Mscf/D Maximum Well Life = 50 Years Continuously Unloaded Cyclic Shut in Control Liquid Loading Start of Liquid Loading 1E 5 1E 4 1E 3 1E 2 1E 1 Permeability, md 11 Horizontal Multi-Fraced Well

12 No Delay in Recovery Horizontal Multi Fractured well Continuously-Unloaded (no shut-ins) = Cyclic Shut-In (1-day shut-ins) 12 Horizontal Multi-Fraced Well

13 Optimal Cyclic Shut In Time 100 Recovery Factor Efficiency, E RF, % E RF =(RF CS -RF LL ) / (RF CU -RF LL ) Horizontal Well Vertical Well Cyclic Shut in Time, days 13

14 Producing to Shut In Cycle Time Ratio 100 Horizontal Multi-Fractured Well Ratio of Producing Time Period to Previous Shut-in Time Period 10 Vertical Well Time Since Onset of Liquid Loading, days 14

15 Layered No Cross Flow Well Single Layer Permeability value: 0.15 md. Thickness: 15 ft. Onset liquid loading: 1144 days. Average reservoir pressure: 1973 psia. Two Layers Layer 1 Permeability: md. Thickness: 2 ft. Layer 2 Permeability: md. Thickness: 13 ft. Onset liquid loading: 424 days. Average reservoir pressures: Layer 1: 1783 psia. Layer 2: 2216 psia. 15

16 LNX Average Reservoir Pressures Average Reservoir Pressure, psia CU: Single Layer CS: Single Layer CU: Two Layers (Layer 1) CU: Two Layers (Layer 2) CS: Two Layers Time, Days CU: Continously Unloaded without shut ins CS: Cyclic Shut in Control (1 hr shut ins) Two Layers (Layer 2) Single Layer Two Layers (Layer 1) 16

17 LNX Recovery Factors Recovery Factor, % CU: Single Layer CS: Single Layer CU: Two Layers CS: Two Layers Single Layer Two Layers Time, Days CU: Continously Unloaded without shut ins CS: Cyclic Shut in Control (1 hr shut ins) 17

18 Comments to Cyclic Shut In Wells that have historically produced under liquidloading conditions may require pre treatment liquid removal before / while implementing cyclic shut in. Plunger lift is a form of cyclic shut in. Longer shut in times may be required to build sufficient pressure to lift the plunger+liquid. Horizontal multi fractured wells may have sloshing liquid in horizontal section needs further study. 18

19 Conclusions 1. Cyclic shut in is a simple and cost effective method. 2. Cyclic shut in should minimize recovery loss and delay caused by liquid loading. 3. Ultimate recovery rate with cyclic shut in control is similar to a continuously unloaded well. 4. Cyclic shut in is best suited for low permeability and ultra low permeability wells. 5. Cyclic shut in is equally valid for layered no crossflow reservoirs. 19

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21 Gas Recovery Efficiency Vertical stimulated well Cyclic Shut in t SI =1 hr t SI =1 day Post Liquid Loading Recovery Factor Efficiency, % t SI =10 days Liquid Loading Permeability, md 21 Vertical Well

22 Gas Recovery Efficiency Horizontal Multi Fractured well 100 Cyclic Shut in t SI =1 day & 1 hr t 90 SI =30 days Post Liquid Loading Recovery Factor Efficiency, % Liquid Loading 0 1E 5 1E 4 1E 3 Permeability, md 22 Horizontal Multi-Fraced Well

23 Percentage Producing Time Producing Time Since Liquid Loading, % of Time Since Onset of Liquid Loading Horizontal Multi-Fractured Well Vertical Well Time Since Onset of Liquid Loading, days