High Pressure Continuous Gas Circulation: A solution for the

Transcription

1 Gas Well Deliquification Workshop Sheraton Hotel, February 20 22, 2017 High Pressure Continuous Gas Circulation: A solution for the Pressure Dependent Permeability of the Haynesville Shale? Bill Elmer, P.E. Encline Artificial Lift Technologies LLC

2 What is PDP? Pressure Dependent Permeability caused by: Stress dependent permeability Proppant embedment Proppant crushing? Results in severe productivity loss 2

3 Where is this PDP observed? Documented in the Haynesville Shale by SPE papers: SPE : Estimated Ultimate Recovery as a Function of Production Practices in the Haynesville Shale, Mangha et al, 2011 SPE : Diagnosing Pressure-Dependent- Permeability in Long-Term Shale Gas Pressure and Production Transient Analysis, Vera & Ehlig- Economides, 2013 SPE : Integrated Haynesville Production Analysis, Hao et al,

4 Normal deliquification practices hurt shales with PDP Haynesville wells produce salty water and lean gas Normally flow at high rate on initial completion into 1000 psi gathering system Exhibit liquid loading when rates fall to 1000 to 1200 MCFPD up 2-7/8 tubing, as expected with salty water Normal practice of reducing tubing pressure to restore critical flowrate causes further permeability reduction Also exacerbates salt formation problems, fuel intensive Liquid loading occurs again within 12 months as rate falls below 400 MCFPD 4

5 CGC - CO Operating Mode This slide and next two are courtesy of Jim Hacksma, industry s CGC expert CO = Circulate Only Does Not Reduce FTP When Should CO Mode Be Used? When LP Is Already Relatively Low OR.. When Little Production Is Gained By Reducing FTP This is the Haynesville Shale, due to PDP 5

6 CGC EXAMPLE (Courtesy Jim Hacksma, modified for Haynesville Shale) Separator Compressor Motor Valve Sales Meter Well Capable Of Only 100 MCFD Sales Critical Rate Is 1000 MCFD (loading problem) Design Compressor To Circulate 1000 MCFD Total Flow Up Tubing Is 1100 MCFD Now Above Critical Carries Out Liquids If Sales Decline To 0, Still Carries Liquids Thus, A Permanent Solution 6

7 SAME RATE UP TUBING SAME FBHP 7

8 Is CGC a better way to solve loading issues than reducing pressure? For a reservoir with PDP like the Haynesville, with repeatedly demonstrated productivity decreases as FBHP is lowered, most certainly. The real question is: What is the minimum FBHP target desired to minimize the impact of PDP What do the three SPE papers say about this? 8

9 SPE Conclusion For reservoirs which are significantly overpressured as in the case of the Haynesville Shale, it should be kept in mind that permeability would likely decrease as a function of reservoir pressure. Higher drawdown would cause higher effective stress fields, which would decrease productivity. Under these circumstances, controlling or better managing drawdown could be a solution to prevent severe production loss. Paper did give pressure drawdown guidelines 9

10 SPE Conclusions Made point that PDP is best diagnosed with pressure buildup transient tests Suggested using permanent downhole pressure gauge or casing pressure data during shut-ins Attributed productivity losses to both hydraulic fracture and shale effective permeability reductions Paper did give pressure drawdown guidelines 10

11 SPE Paper reviewed multiple models used to predict EUR s Concluded that permanent downhole pressure gauges and PLT were needed for Pressure Transient Analysis and Rate Transient Analysis Never offered insight into how to mitigate PDP It is evident that pressure depletion is confined mostly to the fractures and does not extend deep within the formation, as would be expected in a tight shale system. It indicates the strong geomechanical effects and low permeability are the dominant production mechanisms that prevent the unstimulated volume from producing effectively. 11

12 Operators left to trial and error to manage drawdown versus productivity It is very important to realize that low FBHP does not equal low BHP in the formation Low FBHP not seen by formation, as fracture permeability and formation permeability reduced Conventional gas well deliquification logic does not apply BHP reductions normally access more reserves, not less PDP is the reason why Necessary to maintain high FBHP s for many years Blowing well down could reduce reserves by multiple BCF 12

13 Is CGC a better way to solve loading issues than reducing pressure? It should be, as CGC simply keeps velocity up the tubing at critical rate, regardless of the pressure Will show that High Pressure CGC uses far less Horsepower than lowering line pressure Offers a permanent solution for liquid loading, not a twelve month solution Saturated gas injection should reduce salt problems Offers method to transport corrosion and scale chemicals, and fresh water downhole Due to low velocities, can be performed down concentric tubing instead of tubing-casing annulus 13

14 How high is the pressure requirement? Production data from the Haynesville showed that psi casing pressure with 1000 psi tubing pressure common prior to loading at critical rate of 1000 MCFPD High pressure CGC would require compressing gas from 1000 psi up to 1700 psi, which is only 1.7 compression ratios Simple single stage compressor job, no gas cooler required Low horsepower lends itself to running off single phase grid electricity 14

15 Won t this high casing pressure keep the bottom hole pressure elevated? Yes, we are counting on this to prevent loss of permeability and reserves! Haynesville initial reservoir pressures above psi Can PDP be mitigated by keeping FBHP above 5000 psi? 4000 psi? 3000 psi? 2000 psi? 1700 psi? Don t know the answer, just that CGC can do this today Will give use 1700 psi as an example 15

16 Horsepower Comparison Turning loaded up well into lower pressure pipeline is common place, but requires 130 HP per MMSCFD Two stage compression normally costs 10 to 20 cents per MCF All produced gas is compressed reducing reserves by 2.38% for fuel associated with 130 HP per MMSCFD High Pressure CGC, only the circulated gas is compressed Circulated gas only requires 35 HP per MMSCFD Single stage compressor, especially electric, is simple 16

17 Compressor Design for 1700 psi Heading Point 1 Point 2 Point 3 Point 4 17

18 Fuel Use as a percentage of Well Rate Well Rate Injection Rate Total Rate Fuel at 0.672% 700 MCFPD 500 MCFPD 1200 MCFPD 3.36 MCFPD 0.48% % % % % % % Fuel as a percentage of Well Rate Only when rate falls below 300 MCFPD does fuel use with CGC exceed lower wellhead pressure fuel use of 2.38% However, the lower pressure well loads up at 400 MCFPD 18

19 How much Horsepower required for CGC with no well contribution? Casing Pressure Tubing Pressure Compress Ratios HP/ MM Coleman Critical rate MM 36.8 HP Required MM MM MM MM 19.8 These numbers are based on the assumption of 700 psi of friction and fluid gradient across the tubing 19

20 Compressor Design for High Pressure CGC at high pressures up to 4700 psi is possible because: Production casing no longer rated to 2000 psi, but Advent of CNG caused development of high pressure compressor cylinders (just need to build compressors) Since HP requirements are so low with CGC (< 50 HP), reliable electric power is ideal VFD technology can convert readily available single phase power to three phase power at negligible cost VFD can change compressor speed to deliver exactly critical flow from the well, no more (causing friction) or no less (causing loading) 20

21 Conclusions Pressure Dependent Permeability that is present in the Haynesville Shale requires that we dispense with previous ideas on using lower pressure to maintain critical velocity Since Haynesville operators attempt to avoid huge productivity losses (and drastically lower EUR s) by maintaining higher FBHP s, High Pressure CGC offers the ability to permanently solve liquid loading issues without endangering completion competency High Pressure CGC will require building compressors that are not currently available for rent 21

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