gas well de-liquification workshop denver, colorado february 27 - march 1, 2006 problem...

Gas Well De-Liquification WorkshopDenver, Colorado

February 27 - March 1, 2006

Problem Identification, Candidate Selection, & Selection of Artificial Lift Technique

Rick Hornsby – Breakout Coordinator

Feb. 27 - Mar. 1, 2006 2006 Gas Well De-Liquification Workshop Denver, Colorado

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Good surveillance & identification of problem wells

• What specific data do we need to look at (tubing size, casing size, liner size, flowing tubing pressure, etc.)?

• How do we determine a well’s critical liquid loading rate?

• What can we learn from evaluating historical production plots?

• What do the liquid (water, condensate) rates, or lack thereof, tell us?


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Discussion Summary – Identification of Potential Candidates for Artificial Lift

–Chemical composition, salinity of water?

–Condensate or oil?

–Reservoir temperature

–Baseline – production when well was flowing OK.

–Tubing pressure, casing pressure, tubing size.

–Casing and tubing integrity.

–Corrosion inhibition needed?

–Fluid level.

–Well’s IPR, Static BH Pressure, Flowing BH Pressure.

– Well’s decline rate.

– Decline rate vs. cum’l production.

– Nodal analysis.

– System analysis.

– GLR.

– Calculated gas velocity.

– Presence of slugging.

– Available facility.

– Gathering lines, compression.

– Compare actual performance vs. model of gas well performance.


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Selection of those problem wells where artificial lift will result in an economical investment

• What can we learn from our lease operators about well performance?

• What operations techniques lead us to believe a well is a good artificial lift candidate (soap sticking, intermitting, stop-cocking, venting, swabbing, etc.)?

• What low cost actions can be taken to ‘prove up’ a good candidate (soap sticks, batch soap treatments, swabbing, flowing bottomhole pressure surveys, etc.)


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Discussion Summary – Selection of Candidates for Artificial Lift

– Obtain Operator’s feel on liquid cuts, or gas and liquid rates.

– Obtain Operator’s feel on sensitivity to back pressure.

– Understand Operator’s problems keeping wells on production – soaping, stop cocking, etc.

– Hold well reviews. Talk to Operators. Supplement well file.

– Provide field training of engineers.

– Run integrity surveys – check for fill.

– Use coiled tubing with N2 or CO2 cleanout.

– Use stimulation to reduce water blocks in near-wellbore area. Do lab analysis first.

– Can’t necessarily count on batch treatment to confirm or rule out suitability for cap tube. Be careful.

– Can use a portable cap tube to reduce “testing” cost.


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Selection of the most appropriate type of artificial lift

• What makes a good plunger lift candidate?

• What makes a good surfactant injection candidate?

• When is it necessary to consider more costly types of artificial lift (rod pumps, ESP’s, jet pumps, progressing cavity pumping, gas-lift, wellhead compression, etc.)?

• Do ongoing operating expenses matter and can the answer to this question determine the selection of the technique in the first place?

• How important are electronic flow measurement and automation (remote well control) to the success of the system?


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Discussion Summary – Selection of Type of Artificial Lift

• For plungers:

– ROT is 400 cf/bbl/1000 ft.

– Not below 2 3/8 or 2 7/8 tubing size.

– No holes in tubing, or insert profiles.

– Not too high GLR.

– Conventional vs. slim hole completion – communication with annulus.

– Plunger depth vs. depth of perfs.

– Up to 30o from vertical, not have doglegs.


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• For surfactant:

– High WCR.

– Holes in tubing don’t rule it out.

– Tubing ID doesn’t need to be unobstructed.

– High deviation is OK.

– Low Operator / Service Company crew availability.


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• For pumps: – Need to obtain very low FBHP.

– Electricity or other power source at well site.

– Amount of water that needs to be produced – beyond limit for plunger or chemical.

– Gas interference is a problem.

– Intervention costs may be high.

– Safety issues with sour gas wells.

– CAPEX.

– Subterranean hydraulic driven rod lift a possibility.

– Depth limits, deviation, dog legs, rod wear must be considered.

– May choose PCP if have solids.


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• Automation:

– Needed regardless of type of artificial lift.

– High value of gas.

– Pressure on operating staff.

– Essential for focus on HSSE.

gas well de-liquification workshop denver, colorado february 27 - march 1, 2006 problem...

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