2 nd Annual Appalachian Basin Gas Well Deliquification Seminar Hilton Garden Inn, Pittsburg, PA June 13-14, 2011 Beam Pumping to Dewater Horizontal Gas Wells Lynn Rowlan, Echometer Co. J F Lea, Production and Lift Technology (PLTech) LLC N W Hein, Jr., NPS Norris/AOT
Fractured Horizontal Wells Preferred for Shale Gas Wells Difficult to Set Pumps Perforations Many horizontal gas wells are dewatered using gas lift. However there are advantages to using beam pumps that still can be considered. 2
Overview: Why Horizontal? Higher Productivity Improved Drainage Extended Reach Intersect Multiple Pay Shales? must also fracture 3
Production from Shale Gas 4
Shale Gas Future 5
Horizontal Well Ideal Case 6
Complex Horizontal Well Profiles True Vertical Depth, ft 10,100 10,150 10,200 10,250 10,300 Complex Horizontal Well Profiles Well 1 Well 2 Well 3 Well 4 Well 5 Well 6 Well 7 Well 8 Well 9 10,350 10,400 0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 Departure, ft 7
L5 with Poor Control of Deviations in Horizontal Along the Length Resulting in Many Sumps or Undulations vs. Controlling Deviations in L10 SPE75249 8
TWO PHASE HORIZONTAL FLOW PATTERNS J F Lea PLTech LLC 9 9
Horizontal Wells Three Profiles Drilled up from the kick off point Approximately horizontal from kick off point Downward from the kick off point 10
Horizontal Wells Three Profiles Store and Slug Gas Stratified Gas Flow Difficult to Draw Down 11
Horizontal Plunger Lifted Well Tubing Depth: 7588.90 ft Toe 9610 ft GLV 1 @ 1712' GLV 2 @ 3014' GLV 3 @ 4092' GLV 4 @ 4797' GLV 5 @ 5256' GLV 6 @ 5716' GLV 7 @ 6176' GLV 8 @ 6570' GLV 9 @ 7031 Gas Lift Valves Used To Confirm Up Kick Selected is the Top Of Perfs 12
Can Shoot Fluid Level to Toe Due to Stratified Gas Flow in Horizontal Perf DM- -EOT 3 4 5 6 7 8 9 Perf EOT 1. Gas gun was charged to 800 psi to create this shot. (CP=226 Psig) 2. Red line and valve number identify the gas lift valves echoes on the acoustic trace. 3. Top perf up kick echo was used to determine the depths in the well. 13
Stratified Gas Flow Regime Exist in Horizontal Gas Wells 1. Fluid level shot down the tubing/casing annulus shows a liquid level at a MD of 9283. 2. Being able to see past the end of the tubing is unusual in a vertical plunger lift well, because the liquid level is normally at the end of the tubing. 3. In horizontal wells stratified flow exists; it is not uncommon to see features in the well bore in the horizontal section past the end of the tubing. 4. Horizontal section appears to be relatively dry (no liquid level); but significant amount of liquid enters the tubing. 5. Differential tubing and casing pressure do not indicate much liquid loading, but liquid exist in horizontal and causes more liquid loading than expected (based on tubing & casing psi). 14
Shows Pump Can be Set in the Near Vertical Section of a Horizontal Well 15
ANOTHER VIEW OF PACKER-TYPE GAS SEPARATOR 16
Basic Principles of Downhole Separator System Downhole separators must be efficient, low cost, trouble free, long lasting. Gravity separation is the governing principle for plunger pump installations. Many designs have been proposed (over 75 US patents) but only those that satisfy the above conditions are used in practice. Centrifugal separation applied in ESP systems (will not be discussed here) V slip V liquid in anchor V gas in anchor V plunger 17
Liquid Should NOT Flow Too Fast into Gas Separator GAS SEPARATOR LIQUID CAPACITY IS BASED ON THE FOLLOWING PRINCIPLE: Gas GAS BUBBLES FLOW UPWARD IN OIL OR WATER AT A RATE OF APPROXIMATELY 6 INCHES PER SECOND. THUS, GAS BUBBLES WILL BE RELEASED FROM A LIQUID COLUMN IF THE DOWNWARD LIQUID VELOCITY IS LESS THAN 6 INCHES PER SECOND. A LIQUID COLUMN HAVING AN AREA OF 1 SQUARE INCH TRAVELLING AT A RATE OF 6 INCHES PER SECOND IS A RATE OF APPROXIMATELY 50 BPD. 18
Natural Gas Anchor The most efficient downhole separator requires locating the pump intake below the lowest gas entry point. 19
Improved Natural Gas Anchor Maximum flow area in annulus below pump. 20
Natural Gas Anchor Liquid Capacity for Various Annular Areas 21
Poor Boy GAS SEPARATOR Small Area Collars force inlet ports away from casing wall 22
Flow Area inside Separator Limits Liquid Capacity. 3/8 inch perforations limit gas exit flow and liquid entry thus reducing separation efficiency 23
Poor Boy Separator Liquid Capacity 24
Weighted Intake- Bottom Feeder- Inclined or Horizontal- Takes advantage of stratification if present John Haverko General Manager Premium ALS Main: (403) 723-3008 Fax: (403) 723-3011 Cell: (403) 880-2144 email: jhaverko@premiumals.com 25
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Shrouded in a Sump ESP below perforations or in a sump. Gas slugs do not enter the sump, Shroud is required for cooling Shrouded ESP Baker Hughes 27
For Inclined Wells Baker Hughes 28
Pump for Dewatering: 1) Gas flows up the annulus 2) Liquid pumped up the tubing Possible pump locations: 1)Locate in straight section 2)Locate in curved section 3)Locate in Horizontal Disadvantages: 1) Slugging of Liquids 2) May not achieve the lowest possible drawdown 3) Gas separation requirement is present. Life should be same as for pump in vertical bore; but problems due to poor gas separation since the intake cannot sit below perforations. 29
Pump: In curved section 1) According to HF, a Two Stage Hollow Valve Rod Pump (2SHVR) with a Flexite Plunger is best. 2) Flexite rings contact the barrel 3) If not thinner wall box end plunger is more flexible than pin end 4) Set in straight but inclined section if possible Pumps problems setting in the curved section may include: 1) Broken valve rod 2) Broken upper plunger pin 3) Worn valve rod or pull tube 4) Worn valve rod or pull tube guide According to HF Pumps the pump life can be 30 % of setting in the near vertical. 30
Pump: In the Horizontal If the pump and rods can be run in the horizontal: 1) Standard valves still open/close 2) Guided/lined cages extend life HF recommends: 1) Use rod rotator 2) Leave off guide collar in curved section 3) 10-12 molded on guides/rod in curved/horizontal sections 4) Use pump guide collar on top of the pump to centralize smaller pump in tubing. 5) Pumps have been run through 20-24 deg/100 Pump may last 60% compared to setting in the vertical 31
156 bpd from 10,000 feet (Bakken?) 32
10,000 ft, 10 bpd, 2.2 hp required 33
Measured Surface Dynamometer Card and Horizontal Well Profile Standard 1.5 inch Diameter API Pump Normal appearance and loadings Sucker Rod Pump Set 800 Feet into Horizontal Section
Summary Beam systems are more expensive than many dewatering systems Energy costs are low if lifting small amounts of liquids Service costs can be high with crooked wells, sand, scale, etc With low CHP, beam can provide very good drawdown best? Beam can be used with deviated wells with smooth buildups, and low dog leg severity 35
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