1. Optimization of Liquid-Rich Shale Gas Wells using Multi-Channel Production Tubing Technology Commercialization Corp. 219 Blood Rd. Chester, VT 05143 MWKen77@gmail.com www.mcs-systems.com

2. Production Optimization Liquid-rich shale wells produced at low bottomhole pressure in efforts to increase early gas rates comes at the expense of reduced oil recovery – Most shale oil that condenses below oil dewpoint pressure in near fracture region is not produced to surface (immobile due to high capillary forces in shale) Producing at high bottomhole pressure The key is for liquids to condense in the well tubing, not the reservoir Gas entering wellbore contains more oil (in gas phase), increasing the oil-gas ratio at surface Increases ultimate recovery of liquids, at the cost of delaying gas production

3. Producing at High Bottomhole Pressure But producing at high bottomhole pressure promotes liquid loading – Reduces gas production (lower gas velocity) – Results in earlier need of artificial lift operations, greatly increasing production costs For 4-inch ID tubing, the well required artificial lift after 25 days !!! For 2-inch ID tubing, the well required artificial lift after 2 years

4. Critical Flow Velocity -Energy transfer -Reducing tubing diameter increases extent of energy transfer from the carrier phase (gas) to the carried phase (liquid) - Potential energy of gas is released as pressure declines up well - Reducing tubing diameter increases interaction between the phases - Reduces slippage of gas past liquid -There is a minimum gas flow velocity required to prevent liquid accumulation in a gas well… maintaining steady state flow -Petroleum engineers decide on well tubing diameter based on characteristics of the well using well-accepted correlations -As a reference point, this “minimum velocity” of gas up a 2-inch diameter well is > 20 feet- per-second (fps)

5. Multi-Channel Production Tubing Specifically designed for multi-phase flow An “MCS” divides the flow up well into multiple flows through passageways having the same diameter Increases the transfer of energy from gas to liquid – Separates decision of tubing diameter from flow volume considerations Permits production tubing to be designed for targeting a minimum flowrate to maintain steady state flow, avoiding artificial lift altogether – Minimum steady state flowrate can be as low as 1 fps (vs. 20 fps in 2-inch tubing) Number of passageways can be increased to accommodate any flow volume – Restriction penalty (choking) of using a smaller diameter tubing is avoided – Flow volume can be greater than conventional tubing, given the compromises associated with using one diameter tubing over the life of the well – Increases ultimate recovery, while at the same time enabling maximization of near-term production – No outside energy, consumables or maintenance are required – Patents in US and Canada

6. Pilot MCS Gas Well 1,930-foot conventional vertical tight gas well – When the well was new, the peak gas flowrate was 120 Mcf per day (steady state flow) Production tubing was 2-inches ID Immediately before MCS production tubing installation – 280 psi bottomhole pressure and 70 psi at top of well – 2-week intermittent slugging cycle (surfactants used to help unload water) After MCS production tubing installation – Automatic kick-off (evacuation of 360’ of standing liquid), then flow was steady state thereafter (three plus years, no maintenance) – Production increased by 30%, to 20 Mcfd Produced 2.7 Bbl of water per day (~130 Bbl/MMcf) Flow performance through MCS production tubing – Calculated gas velocity was 4.4 fps at well bottom and 11 fps at wellhead Proved that reducing flow diameter reduces the minimum flow velocity required to maintain steady state flow (vs. >20 fps up 2-inch tubing) – Minimum flow velocity to maintain steady state flow is estimated at ~1 fps Ultimate recovery is estimated at over 75% of gas remaining in reservoir at time of MCS installation, recovered over an estimated 10 to 15 year period Payback period was 100 days – Revenue: (20 Mcfd) x ($2/Mcf) x (100 days) = $4,000 – Costs: (2,000 foot extrusion) x ($1.50 / foot) + ($1,000 in other expenses) = $4,000 Least expensive alternative is “plunger lift”, initially costing over $5,000 plus ~1,250 / year (requires close oversight and periodic adjustments)

7. MCS Production Tubing for Liquid-Rich Shale Gas Wells (MCS vs. 2-inch ID production tubing) Benefits – MCS design example: 6 one-inch (or less) ID production tubes embedded in extruded plastic and possibly encased in steel Similar “coiled tubing” design is now used for cleanouts (FlatPak): two tubes drive a downhole hydraulic pump and a third tube produces the liquids/solids Increases near-term production volume (less restrictive) – Greater flow area of MCS vs. 2-inch ID tubing Predicted to reduce the Minimum Flow Velocity by a factor of ~ 2 – Results in steady state flow through 5-year period (double 2-inch tubing) Improves “flow assurance” (probability of well flowing as designed) – If flow ever becomes intermittent, individual one-inch tubes can be closed to reduce flow area and further extend steady state flow – To initiate kickoff of well loaded with liquid, all but one of the one-inch tubes can be shut in, with the remaining one-inch tube used to drain accumulated liquid – Other MCS designs can be made for other production objectives Such as greater near-term production, or lower minimum gas velocity for steady state

8. MCS Production Tubing for Liquid-Rich Shale Gas Wells (MCS vs. 2-inch ID production tubing) Costs – 2-inch ID production tubing represents less than 5% of total well costs MCS production tubing will cost about 2 to 3 times the cost of conventional 2-inch ID steel production tubing A number of US petroleum supply companies now produce multi-tubular coiled tubing capable of high-pressure environments (FlatPak, FiberSpar, etc.) – See picture below for example of spoolable composite production tubing » Can be redesigned/ repurposed as MCS production tubing – The higher cost of MCS tubing is more than compensated for by avoiding the cost of artificial lift Artificial lift is very expensive, both in capital and operational costs (labor and energy) – High-pressure pumps and compressors » Expensive to purchase, power, maintain and replace » Increased production complexity reduces reliability of well to flow MCS production tubing significantly increases the efficiency of artificial gas lift operations

9. MCS Development Timeline Pilot MCS gas well – Demonstrated benefits of MCS in live conventional gas well (1930 feet) Steady state flow for over 3 years – no maintenance – Projected to flow at steady state rate for 10 to 15 years Payback period was 100 days MCS polymer extrusions introduced for sale in June, 2016 – Production in Canton, OH – Two MCS designs will be available in stock for low-pressure wells with well depths of up to 4,000 feet (stripper gas wells) Diameter of 1¼-inches, having seven holes of 7mm each – Flow range of 8 to 40 Mcfd (for sale at $1.50 /ft.) Diameter of 1 inch, having one 7mm hole and six 5mm holes – Flow range of 1 to 12 Mcfd (for sale at $1.20 /ft.) – Other MCS designs are available by special order in 2016 Higher tensile strength (stiffer) polymer blends for well depths of up to 3,500 feet Embedded stranded wire MCS extrusions for depths up to 9,000 feet Larger diameter MCS designs for gas flow rates of up to 1 MMcfd or more

10. MCS Development Timeline MCS production tubing for liquid-rich shale gas wells – High-pressure wells require individual MCS passageways to be reinforced to resist bursting or being crushed A number of contractors are available to accomplish the needed MCS construction – Experience Well performance data gained from 2016 MCS installations in conventional shallow, low-pressure gas wells (stripper wells) will improve prediction and execution capabilities for deeper, high-pressure wells – Potential Partners Operators of shale gas wells seeking to improve the efficiency of their wells – Most operational/ engineering tasks can be subcontracted – As multi-phase flow specialists, we can help select best candidate wells and assist in developing flow models Venture capital firms having partnerships in the industry

11. Other Potential Applications for MCS Production Tubing Risers – Any multi-phase riser over 2-inch ID is hugely inefficient – High gas slippage rates (gas has low efficiency in lifting liquid) – Offshore - secondary MCS riser patched in at seabed to produce well fluids – Onshore - secondary MCS riser in upper region of well (where casing size allows) – Eliminates formation of huge liquid slugs in risers that can damage the production tubing and surface facilities Oil Wells – During initial fountain stage, gas inefficiently lifts the oil in conventional tubing Given greater efficiency of an MCS, the initial natural flowing phase of an oil well can be extended by up to three times, forestalling artificial lift By conserving gas in reservoir, using an MCS will result in less oil stranded in the reservoir (solution gas lowers the viscosity of oil to help it flow to wellbore) Partial surface choke, utilizing an MCS, where energy is utilized (vs. dissipated) – In gas and oil wells, energy is wasted/ rejected at the surface choke to control flow » If there is any liquid accumulation in the well, an MCS can utilize part of the energy rejected at the choke to assist in lifting the liquid » A conventional surface choke is used for final adjustment of flow Offshore MCS jumper lines from wellhead to surface facility or ship, eliminating liquid slugging and reducing slug-catcher capacity at surface – Space is at a premium on offshore platforms, and slug-catchers are large and often a source of production problems