Gas Well Deliquification Workshop Sheraton Hotel, February 23 25, 2015 Gas Assisted Rod Pump Daryl Mazzanti Executive VP Operations GARP Services LLC A subsidiary of Evolution Petroleum Corp (EPM- NYSEMKT)
Gas Assisted Rod Pump (GARP ) A method of removing liquids from gas wells Two stage lift process using gas lift and a rod pump in same wellbore Effectively lowers BHP without significant back pressure Effective for vertical, deviated, and horizontal wells Also effective for wells that are too deep for conventional artificial lift and wells with long perforated intervals Works for wells with casing sizes 4-1/2 or larger 2
Stages of Lift for Gas Wells After the Free Flowing period, the stages of art lift. Intermediate Liquid Loading Stage Mainly Gas Lift Mid Life to Stripper Gas lift becomes inefficient Options are limited Mainly plunger lift, stop cocking, soap strings high GLR makes positive displacement pumps ineffective Stripper Stage mainly plunger lift & stop cocking but these lift methods do not effectively lower BHP 3
Summary of Issues Gas Lift significant back pressure with depth Rod-ESP- issues w/ gas & solids interference, depth limits, failures in deviated sections PC pumps-failures in deviations, limitations for depth & high gravity hydrocarbons Jet Pumps- environmental concerns w/ circulating high volumes of power fluid, depth limits, concerns with inefficiency/high op costs, cavitation issues Hydraulic Piston Pumps- issues with gas/solids, longevity of down-hole equipment Plunger-soap strings limited operating conditions & do not significantly lower BHP 4
Problems with Pumps in Gas Wells High gas to liquid ratios or gas slugging (poor gas separation - worse for smaller csg sizes that use conv tubing anchors) Deviated sections horizontal and deviated wellboreshigh op costs/poor gas separation Deep reservoirs impractical high installation/op costs Long perforated intervals risk of sticking pumps in perforated interval + poor gas separation 5
Why Rod Pumping a High GLR Well Can Be Ineffective Condensation raining down from casing wall can collect Tbg anchor can restrict gas and stack above anchor flow in small csg sizes restricting gas and liquid flow placing back pressure on the reservoir & causing gas Back pressure to back up under the anchor Also gas anchors in small casing sizes have a insufficient cross sectional area resulting in too high of a velocity for gas break out i.e., gas will enter intake Reservoir Feb 23-6, 2015 6
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Current Artificial Lift Options 1. Opt to not install art lift or place lift equip in the vertical section many hundreds to thousands of feet above the reservoir 2. Reluctantly install conventional art lift into these regions or conditions and live with poor efficiency and high work over costs Both options are inadequate: Lead to lower production and reserves Pre-mature well abandonment with loss of leases 8
What is GARP? How does it help? Patented and Patent Pending technology Utilizes two conventional artificial lift technologies in an unconventional way dual tubing arrangement in a two stage lift process in the same wellbore Utilizes the strengths of both methods and minimizes their weaknesses Gas lift does the light lifting of liquids up to the rod pump which then does the heavy lifting to the surface Two version Big Bore (7 csg or larger) & Slim Hole (4-1/2 or larger) 9
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When to use GARP? Whenever lowering the BHP will lead to a production/reserve increase that will justify the costs of the installation. Intermediate-midlife stages for rate acceleration Stripper stage - increases in rates, reserves, life 12
Predictive Methods PI/IPR obtain rate increase from graph with the corresponding drop in FBHP. GARP works better for high perm/eur wells i.e. more permeability equates to higher reserve remaining Decline Curve used for wells with sufficient history look for evidence of liquid loading - off trend production To date, for marginal wells, the technology has demonstrated a reserve increase from ~20-35% of the prior cumulative production with a 10+ fold rate increase in total fluid production 13
Morgan Kovar #1 Rate vs Time 685 MMCF + 234 MBO = 348 MBOE 14
Morgan Kovar #1 Rate vs Cumulative 15
Selected Lands #2 Rate vs Time 16
Selected Lands #2 Rate VS Cumulative Increase of 29% 17
Philips #1 DL Rate vs Time 18
Philips #1 DL Rate vs Cumulative Increase of 37% Increase of 37% 19
Philip DL #1 DYNO 20
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Advantages Installs in 4-1/2 csg or larger for a wide range of rates from 1 to +1000 BFPD w/ < than 6 in/sec fluid velocities Lowers BHP for rate acceleration & increase in reserves Pump no longer has to be lowered to the liquids - Gas lifts liquids to the pump. Able to use smaller pump jacks Field staff is familiar w/ rod pump & gas lift More efficient chemical placement & paraffin reduction SV prevents load water from overwhelming reservoir & allows backside injection to free stuck pumps 25
Rod Pump Tbg Hot Inj Gas heats/insulates Continuous treat inject rod pump tubing to eliminate chemicals with gas or reduce formation of paraffin 2-7/8" Tbg 5-1/2" CSG Shroud Bi-Flow Tool Bushing 1-1/4" tbg Shear Sub Pkr Reservoir Top Reservoir Top - Standing Valve will seat during back-side flush -No more overwhelming the reservoir w/ load wtr from chemical/paraffin or trying to free a stuck pump Reservoir Bottom Reservoir Bottom 2013 Sucker Rod Pumping Workshop Opt : Sand Screen 26
Production Rates Rates are dependent on gas separation efficiency, pump depth, and size/specs of rods, pumping unit, pump, and tubing Summary Max Rates: Slim Hole Design (4-1/2 +) 120-380 BFPD (working on a design for up to 645 BFPD) Big Bore Design (7 +) 1000-1200 BFPD (working on a design for over 1400 BFPD 27
Disadvantages BHA must reach TD. No obstructions Does not overcome inherent limitations in down-hole pumps- limited prod range, plugging w/ fines, maintenance & work-overs Costs more than a conv down-hole pump installation. Depends on numerous factors but the capital costs maybe as low as $100K. Re-useable equip is 2/3 of cost A pressure gas source is necessary. Compressor rentals are available ~$1750/mo or build for ~$40K 28
GARP- The Future Currently working on different design to cut the installation costs for the big bore design Currently working on incorporating an effective solids screen to extend the pump life for wells with high solids to reduce stuck pumps Currently working on a patent to prevent solids from potentially sticking the packer. Although we have had NO sticking problems to date Currently working on utilizing different lift methods other than rod pumps and gas lift 29
Contact Info Daryl Mazzanti Executive VP Operations dmazzanti@evolutionpetroleum.comdleum.com alt email : daryl@garplift.com Office : 713-935-0122 Cell : 281-796-6132 Website : http://www.garplift.comhttp 30
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