Gas Well Optimization & Plunger Lift June 23,2008 Calgary

1. Gas Well Optimization & Plunger Lift June 23,2008 Calgary

5. WCSB has ~ 130,000 producing gas wells with an average production between 6-8 e3m3/day. This would suggest roughly 70% of the gas wells are liquid loaded. • There are roughly 25,000 plunger lift systems operating in Western Canada • A quick guess would TAQA has 5-7,000 gas wells

6. TAQA NORTH • An educated estimate is that we have ~ 2000 plunger lift systems in operation at TAQA. • Potentially 50% of these wells may have opportunity for a 1 e3m3/day gain • So 1000 e3m3/day gain = 353,857mcf @ $10/mcf then $ 350,000.00 day income added or potentially + - 100M /year. • Even at 50% error in estimates there is still substantial gain to be made • This may be achieved with as little as a 15 minute change to plunger cycle times • This does not include wells liquid loaded yet to be identified and solutions applied

7. TAQA NORTH • We are currently Canada’s biggest user of the Zedi –Smart Alek systems • 1224 SA which are used for pressure and volume trending • These all need to be manually adjusted • Who is looking at these regularly ? • we have a total of 20 virtual SCADA and 107 total SCADA • A NRK study determined a substantial gain ( accuracy) using the SA EFM system over conventional charts for plunger lift wells.

8. optimization

9. Plunger cycle tracking

10. Gas flow rate trending / not sales

12. Gas rate trending

13. Stable Flow Unstable Flow Stable Flow Liquid Loading- Loss of Gas Velocity Over Time Well Dead RATE TIME Decreasing Gas Rate with Decreasing Reservoir Pressure Highest Velocity Lowest Velocity Gas Velocity

14. Gas Well Life Cycle Slug Droplet Mist Bubble Gas Flow Decreasing Gas Velocity

15. Top Normal Decline Loading Deviation Plunger Installed Well Production Cumulative Production Increase Time Typical Gas Well Production Decline Curve • Best practice • Optimum curve fit to original production decline

16. Gas Meter MCFD Ftp H2O Stock Tank HP 2P Sep H2O H2O Oil Stock Tank LP 3P Sep Compressor OIL Line Heater AJAX Fcp BOPD BWPD Surface Casing Production Tubing Packer Gas Reservoir – Gas/Oil/Water Present Production Casing Gas Well System

18. Recognizing Liquid Loading • Noticeable decrease in production. • Wells being swabbed, blown down, etc. • Change in production decline curve. • Increased pressure difference between casing & tubing. • Spiking production and casing pressures

24. GAS WELL LOADINGFalling Below Critical Velocity • Critical Velocity = Velocity of the Gas flowing up the production Tubing. • Falling Below CV -causes the liquids to start to fallback and start the liquid loading process • Liquid Loading creates hydrostatic head pressure on the formation • Result - loss in production due to hydrostatic head pressure (back pressure) created on formation.

26. Water Droplet Gravity σ1/4(ρLiquid-ρGas)1/4 ρGas1/2 Vc = 1.593 Gas Flow Turner Equation What Causes it - Liquid Loading: Turner Equation Drag from flowing gas is tending to lift water droplet which is reacting to GRAVITY and trying to remain at bottom of a well. Turner Equation: Calculates Flow Velocity that keeps “Liquid Drop” Stationary in flow stream; Calculate Critical Velocity necessary to maintain Drag Force. VELOCITY OF FLOW IN THE TUBULAR CONFIGURATION THAT WILL CAUSE DROPLET TO REMAIN STATIONARY

27. Most Common De-Watering Methods Velocity Strings Foamer Application Batch Continuous Plunger Lift Other Forms of Lift also used for De-Watering Rod Pumps Gas Lift Hydraulic Lift PC Pump ESP’s Lift Methods Available

28. Velocity Strings • Smaller Tubing String results in reduced flow area, increased velocity and as a result reduced critical velocity rate. • Unfortunately this also comes with an increase in friction • Ultimately there is a balancing act dependent on the rate of decline for the well. A velocity string must be designed with many things in mind (See Next Slide)

31. Adding Foamer • Foamer provides a decrease in density and surface tension which results in a decrease in critical velocity and there for rate. • Batch Treatment is when you pump a large treatment down the tubing, leave the well shut in until it reaches bottom and then bring the well back on. • Continuous includes pumping down the backside and capillary this is a more direct and effective way to lift the well.

32. What kinds of Wells are Better FOAMER Candidates? • Low GAS rate wells (50-250 MCFD) with GLRs between 1,000 and 10,000 scf/bbl are among better FOAMER – CAP TECH candidates (5 to 250 BBL/Day) • MORE LIQUIDS to Foam means MORE CHEMICAL $ spent • Single Liquid Phase is better, 100% Water is best. More than 50% Oil/Condensate is difficult to foam. • There really is no upper limit of GLR.The higher GLR wells may perform better with PLUNGERS which are usually LESS EXPENSIVE TO INSTALL and LESS EXPENSIVE TO OPERATE • The lower GLR wells may perform better with DOWNHOLE PUMPS but efficient downhole gas separation is extremely important and they are usually MORE EXPENSIVE TO INSTALL and MORE EXPENSIVE TO OPERATE

33. Turner Equation FOAM Droplet Cluster Gravity σ1/4(ρLiquid-ρGas)1/4 ρGas1/2 Vc = 1.593 (ρLiquid-0.0031p)1/4 (0.0031p)1/2 Vc = C Gas Flow C = 4.434, water C= 3.369, condensate, p<=1,000 psi. C = 3.369, FOAM Foam Cluster Apparent Density = 6 lbm/ft3 Foam Cluster Water Surface Tension = 20 dynes/cm “Simplified” Coleman Equation Lower Pressures FOAM CASE Liquid Loading: Coleman Equation - FOAM Standard Assumptions that “Simplify” the Turner Equation to the Coleman Equation: • 60 dynes/cm Surface Tension for Water • 20 dynes/cm Surface Tension for Condensate • 67 lbm/ft3 Water Density • 45 lbm/ft3 Condensate Density • 0.6 gas Gravity • 120 oF Gas Temperature • 20% Upward Adjustment – Fit His Empirical Data Coleman eliminates 20% adjustment Vc reduces by factor of +/- 2.5 @ 100 psi 22.8 to 9.3 ft/sec Note: No Friction considered for additional foam viscosity

34. Disclaimer / fine print • I have very little experience with foaming agents but have access to a wide variety of published papers from an assortment of gas well deliquification workshops and would be more than happy to forward or investigate further

35. Stop cocking • Cycling, also known as stop-cocking or intermitting, refers to the process of intermittently cycling the well between flowing and shut-in conditions..  When the well is shut in, bottomhole pressure increases and pressurized gas accumulates in the annulus or near wellbore.  The increased well pressure pushes all or part of the fluids back into the formation, allowing the well to flow again once the well is opened to production.  Typically the key is producing the wells above critical rate with minimal production below critical rate as there is no interface available to lift the fluid in the following cycle.

36. Stop Cocking / Intermitting • The liquid loading of a gas well with produced fluids becomes a problem when the tubing velocity becomes too small to maintain steady flow conditions. The problem is not due to an insufficient GLR, but can be attributed to too low gas producing rate due to low Pr or low reservoir permeability. • When liquids are present larger tubing pressure drops occur at low rates due to liquids accumulation. • Intermittent flow (stop cocking) is when the well is alternately shut in and produced. The objective of intermittent flow is to accumulate enough gas in storage, both in near well reservoir and/or casing annulus, and inject this gas under an accumulated fluid column for a short period of time to produce liquids to the surface. A general rule would require the input of surfacing velocity in excess of 1200 fpm which is estimated to lift liquids in mist flow. This can also be called critical tubing velocity. It is also assumed that the casing storage volume supplies the gas to displace the slug to surface. The gas stored in the reservoir by the buildup provides for sustaining the flow period to ensure liquid removal in spite of flow losses due to gas slippage and liquid hold up in the tubing. • PLUNGER LIFT • The plunger lift installation utilizes a traveling free piston to interface between accumulated liquids in the tubing and the lift gas. Basically it is a more efficient form of lift because the plunger reduces gas slippage and eliminates liquid fallback. There is no minimum critical tubing velocity for liquid production with plungers as there would be for flow up tubing. The operating criteria is based predominantly on the GLR and not the producing gas rate. • Note: A surface velocity of between 500-1000 fmp is generally considered the optimal target range. • As an automated intermittent flow system requires only an equipment savings of <$5,000.00 compared to a plunger lift system, the increase in unrestricted gas production should offer a quick payout for the cost differential The cost of installing downhole and equipment via wireline should be reviewed for convenience’s sake as the intermittent method is only a step away from the plunger lift method. • For accurate predictions in gas well production, a more detailed provision of data is required. Please see the attached form. • The SPE paper #11583 “Gas Well Operation with Liquid Production” by J.F. Lea, Jr. and R.E. Tighe is one of the better publication summaries for reviewing alternate methods for liquid loading problems.

37. Stop cocking • Our experience has shown beneficial gains in production when installing a plunger system over straight on-off stop cocking • eliminating liquid fallback by removing as much wellbore fluid as possible will allow the well to flow at a lower FBHP.

38. Solar Panel Lubricator Catcher Controller Dual “T” Pad Plunger Bumper Spring Plunger Lift SystemsApplications • Unload wells that continue to load up with produced wellbore fluids. • Reduce fallback in wells being produced by intermittent gas lift. • Increase production in wells with emulsion problems. • Enhance production in high gas/liquid ratio wells. • Clean tubing ID in wells experiencing paraffin problems.

39. Solar Panel Lubricator Catcher Controller Dual “T” Pad Plunger Bumper Spring Plunger LiftSystem Advantages • Requires no outside energy source; uses well’s energy to lift • Dewatering gas wells • Rig not required for installation • Easy maintenance • Keeps well cleaned of paraffin deposits • Low-cost artificial lift method • Handles gassy wells • Good in deviated wells • Can produce well to depletion

40. Types of wells needing plunger lift • Intermitting • Shut in and blowing • Soaping • Flowing wells with wide differentials between tubing and casing • Paraffin problems • High line pressure

41. Things needed for a good plunger candidate • Completion • Ideally a consistent ID string of Tubing with the end of tubing into the perforations. • Too high may leave fluid back on perforations possible solution flow tube. • Sumped makes getting gas to the plunger difficult may require perforating tubing. • Rule of thumb say 1/3 into perforations • Better with no packer to use annulus for pressure storage

42. Plunger operating principles • Utilizes the well’s own energy with gas from • formation to drive the plunger to the surface • Well is shut in and the plunger falls to bottom through • the accumulated fluid in the tubing. • The well is re-opened at a pre-determined time or • pressure • The stored energy creates a differential across the • plunger bringing the fluid and plunger to surface

43. Maximum Fluid Recovery • Plunger cycle prevents fluid fallback and gas penetration of the liquid column resulting in the most efficient use of the gas.

44. Since most wells require no packer, the casing and tubing annulus can be used for stored energy. • If well has enough associated gas, this manner of lift can be accomplished with a packer in place.

45. ARTIFICIAL LIFT SYSTEMS • Higher production rates resulting in higher • production • Stabilizing production • Maximizing draw down • Maintaining normal decline curve • Paraffin control

46. Plunger Lift = method of artificial lift that uses well’s gas energy as the prime mover of liquids that have caused loading • Plunger acts as interface between liquids and gas energy • When surface control parameters are met, sales valve opens and exhausts pressure to create differential pressure across plunger • Differential Pressure then lifts liquids & plunger to surface • Sensors record plunger’s arrival, sales time starts • When sales time parameters are met, surface valve closes; plunger goes to off cycle and falls • Cycle repeated

47. plunger candidate • Ability to achieve gas velocity by either • The wells natural flow rates • If a well can flow at over 3 m/s velocity but not over critical it can seal a plunger (see next slide) • Building Pressure • If a well can’t flow over 3 m/s velocity it will require some shut in time to build pressure and achieve a seal.

48. Flowing Wellhead Pressure <1600 kPa No Packer you will need greater than 0.5 E3/m3/1000m Packer you need greater than 1 E3/m3/1000m Flowing Wellhead Pressure >1600 kPa No Packer you will need greater than 1E3/m3/1000m Packer you need greater than 2 E3/m3/1000m Things needed for a good plunger candidate • Production Capability within range of plunger application

49. Things needed for a good plunger candidate • Ability to achieve gas velocity by either • The wells natural flow rates • If a well can flow at over 3 m/s velocity but not over critical it can seal a plunger (see next slide) • Building Pressure • If a well can’t flow over 3 m/s velocity it will require some shut in time to build pressure and achieve a seal.

50. needed for a good plunger candidate • Ability to achieve gas velocity by either • Building Pressure • Quick Tests • Line Pressure X 1.5 = Necessary Casing Pressure Build • Load Factor (Below) (Casing-Tubing)/(Casing-Line)=Load Factor Load Factor needs to be Less than 50% Example SI well Casing pressure = 400 kPa Tubing Pressure = 200 kPa Line pressure = 100 kPa (400-200)/(400-100)=66% (no arrival) Tubing Pressure = 300 kPa (400-300)/(400-100)=33% (should get an arrival)