Gas Well De-Liquification Workshop February 28 - March 2, 2005 Deliquification Short Stories Gordon Gates Deliquification Specialist Bp Houston Assisted By: Danny Patterson, Jess Babbitt, Tony Lott
Does a well load up while Shut In? Not usually There are exceptions to most statements Don t base most of your decisions on exceptions I have seen it with cross flow. 700# zone co-mingled with 110# shallow zone. This particular plunger well takes about 90 minutes of shut in time to load up 2
The Myth of Choking Gas Wells to Keep them producing How many people have heard that you have to hold back pressure on a well to keep it producing? How many agree with that conclusion? If you agree would you hold it on all gas wells? How many of you agree with IPR curves? 3
Typical IPR Curve for a Gas Well Normal Flow Flowing Pressure, psia 400 350 300 250 200 150 100 50 0 0 Choke back to increase BHP Does everyone agree with this? Then why do some people choke back wells? 50 100 150 200 250 300 Rate, mcfd 4
Shot Gun Duals have Cement Bond Problems on the 2 7/8 Communication because of poor Cement Bonding 5
Results of Holding back pressure on Tubing Well is graveyard dead at the age of 500 MCFD 6
MULTI-STAGER TOOL The Multi-Stager creates bottom hole pressure by staging the well, moving part of your energy source under each stage By staging the well with the Multi-Stager tool you lift the fluid load to a shallower depth I like to call it an elevator 7
MULTI-STAGER TOOL CANDIDATES The Multi-Stager has been used in many different well configurations Packer Wells Slim hole Conventional Liner Wells Open Hole Tapered Strings Could it be used in offshore wells with SSSV? 8
Video of Multi Stage Plunger 9
oape 9 Results Installed Multi Stage Plunger Changed bottom Plunger from bar to Pad 10
CGU 9-5 Installed Multi Stage Plunger 11
laspie 4 Flowing up Casing and Tubing 4 PSIG 5.5 Casing 2.375 Tubing 105 PSIG SIBP 4 PSIG Line Pressure 6 Bbls Condensate /MMCF 2 Bbls H2O/MMCF Old EOT @ 6141 Perfs @ 6157 6197 Perfs @ 6240-6248 12
Using tools to understand options Casing & Tubing Flow Casing Flow Only 13
Glaspie 4 flowing up Tubing 4 PSIG Line Pressure 5.5 Casing 2.375 Tubing 105 PSIG SIBP 4 PSIG Line Pressure 6 Bbls Condensate /MMCF 2 Bbls H2O/MMCF 74 PSIG Casing Old EOT @ 6141 New EOT @ 6190 Perfs @ 6157 6197 Perfs @ 6240-6248 14
Using ProdOp to understand your well 15
Glaspie 4 after injecting gas in the tubing Inject 380 MCFD @ 77 PSIG Total Gas Out 1260 MCFD @ 29 PSIG 5.5 Casing 2.375 Tubing 105 PSIG SIBP 4 PSIG Line Pressure 6 Bbls Condensate /MMCF 2 Bbls H2O/MMCF Old EOT @ 6141 Question: What is FBHP? New EOT @ 6190 Perfs @ 6157 6197 Perfs @ 6240-6248 16
After gas lift---net gas today 880 MCF 17
What type of gas should you expect if you lower line pressure from 100# to 30# 10,000 PET SUD;S H COX 002 17031001950000 5,408,845 mcf SLIGO 1,000 Gas Production (mcf) 100 Oil Production (bbl) Water Production (bbl) 10 1966 1970 1974 1978 1982 1986 1990 1994 1998 2002 2006 Time 18
This is what happens when you lower line pressure 19
Why is training and Networking important? You must be able to identify wells that are liquid loaded You must be able to understand why they are loaded Understand tubular limits Pressure limits Rate limits You should understand friction and gravity effects 20
What is this well capable of? 21
What are the issues? It had 2.375 tubing 6000 No packer Less that 10 Bbls /MMCF 275# Build up A compressor that would move Maximum 250 MCFD 2 Flow line that would not get the tubing below 90# to tank 22
Results after optimizing facilities 23
www.texjetpump.com 24
Tex Jet Pump Gas entry point from annuls 25
End View 26
Brown 2 with Tex-Jet Tex-Jet Installed 27
Vortex Flow 28
Wireline Set Tool 29
www.vortexflowllc.com Vortex tool installed 30
Vortex installed 31
Vortex installed (SOAP) 32
This tight gas well makes less than 10 Bbls a day into 650 Psig with 2.375 tubing at 8000. Can we run a plunger on this well? 33
Safety was a concern Within Bp over the last 3-4 years we have launched around 10 plungers This was unacceptable from a Safety standpoint If we do not mitigate this hazard Management will not allow us to use plungers to de-liquefy our wells Working with Hydrates seemed to be one of the root causes of failure The prediction was that this was not possible with the high line pressures that exist in Jonah that range from 550# to 750# 34
Nipple Failure between valves 35
Pacemaker with Hydrate 36
Pacemakers in 600 PSIG line press. Two Piece Installed 37
Don t wait for a well to load up before you spring into action! Action plan for tight gas wells Drill well, frac and produce up 4.5 Casing Monitor flow rate and snubb 2.375 tubing in well before you start to load If liquid rate is too large for plunger then inject surfactant, if not Monitor flow and run two piece plunger in well 100 to 200 MCF before loading Monitor well and lower line pressure when needed 38
Poor Boy Gas Lift and Plunger Assist As reservoirs declines we are installing more and more wellhead compressors This sometimes gives us options for either kicking off wells or sustaining production Basically we add just enough gas into the casing when there is no packer to get the combined flow above critical or just enough to help get a plunger started 39