Hearing How An Operator Monitored Individual Producing Well Pump Intake Pressures To Maximize The Areal Sweet In A CO2 Flooding Operation In The

Transcription

1 Hearing How An Operator Monitored Individual Producing Well Pump Intake Pressures To Maximize The Areal Sweet In A CO2 Flooding Operation In The SACROC Unit, San Andres Presented by: Kim Lomeli 8/26/2015 1

2 SACROC Unit Discovered 1948 Unitized for wtr flood 1952 First CO 2 injection 1973 (immiscible, little tertiary recovery) K-M CO 2 injection 2000 (fully miscible, good tertiary recovery) Patterns 10 Ac. to 90 Ac. Average K 30 md Most wells have ESP s

3 Pressure & Rate Rebalancing P Q

4 D Arcy s Law Differential Form Radial Flow Q KA dp dr Q 2Kh p ln e r e r w p wf

5 Calculated Pressure Gradients, SWCL

6 Pressure & Rate Re-balancing Incremental Oil Response Needs ESP Upsize High GOR Well CTF/SI

7 Pump Intake Pressure (PSI) Inflow Relationships Vogel s IPR Operating Point: psi q (bbls/day) q P. I. p R p wf Productivity Index (PI) q q max 1 pwf pwf pr PR q (bbls/day)

8 An Ideal Pattern for CO 2 Flooding Symmetrical Pattern Equal pressure gradients All layers take fluid Constant thickness Uniform permeability Laterally continuous

9 The Unfortunate Reality Asymmetrical Patterns Variable gradients Multiple layers Thickness varies Permeability varies Discontinuities

10 Step-Rate Testing An initial SRT is run when the well is placed on initial water injection to determine BHP, and the injectivity index. Subsequent SRT s are run annually, when on water during WAG cycles Key objectives: 48-hr shut-in prior to test gives a good estimate for reservoir pressure. Injectivity index is calculated from BHP vs. rate curve. Determination of the formation parting pressure (if observed). Pressure fall-off after last step gives an indication of perm and skin. 10

11 Step-Rate Testing Note the near-wellbore skin effect Skin 11

12 Rapid Pressure Drawdown (IWR < 1) 12

13 Rapid Pressure Drawdown (IWR < 1) ESP Bottom-hole Gauge All ESP s are equipped to record P wf and motor temp. This data is available in real-time and can also be used to track reservoir pressure 13

14 Effect of Pressure Re-Balancing Two months on injection. Two Months on Injection/Production. Boundary No support wells are to drawing the down western reservoir half pressure, of flow paths toward the interior pattern (prior water curtain) Nine months on injection. Nine Months on Injection/Production. Reservoir pressure has decreased in boundary region, flow Large ESP draw down pressure, paths realigned, improved sweep flowlines rearranged, support to west 14

15 Pattern (showing delayed response) 15

16 Rate Re-balancing A direct channel from injector to producer 271-3A overwhelmed the support from adjacent patterns Direct Channel 16

17 Rate Re-balancing With injector shut-in support from adjacent patterns contributed to the response in producer 271-3A 17

18 Rate Re-balancing 271-3A Response to shutting in Response Shut-in 18

19 Pressure and Rate Re-balancing shows the effect of too much water curtain Water Curtain Overran

20 Pressure and Rate Re-balancing After water curtain shut-in well began receiving CO 2 support Water Curtain shut-in 20

21 Response to Pressure & Rate Re-balancing Production After Water Curtain Scaled Back Decrease in PIP Shut-in Water Curtain Increase in Oil, GOR 21

22 New Patterns Affect on Nearby Wells

23 Nearby Well Performance Data

24 Conclusions Successful optimization of a CO 2 EOR project requires intensive and continuous reservoir surveillance. Changing withdrawal in producing wells can have a significant effect on the streamlines between the injector and producers within a pattern. High GOR wells can be managed by downsizing the ESP or by converting to flow. A relatively high processing rate is desirable so that the effects of rebalancing can be observed in a reasonable time frame. High processing rates mean that individual patterns will have a short producing life so adjustments need to be made as soon as the opportunities are identified.

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