Jostine Fei Ho, James Patterson, Shayan Tavassoli, Mohammadreza Shafiei, Matthew Balhoff, Chun Huh, Paul Bommer, Steven Bryant

Research Showcase in Petroleum and Geosystems Engineering • September 8, 2015

Introduction • Existing wells which leak “behind pipe” allow fluids to migrate from one formation to another through a pathway along the cement/earth interface or within that cement • Leakage pathways too narrow to be readily repaired with traditional oilfield cement are nevertheless wide enough to allow significant leakage rates

Key Findings

Research  Showcase  Sponsored  by    

The Use of a pH-Triggered Polymer Gelant to Seal Cement Fractures in Wells

Figure 1. Field application in CO2 storage wells.

1. The reactive polymer solution enters the cement fracture flushing the alkaline brine that was originally in the fracture.

Flow

Diffusion

H+

OH-

Microgel dispersion

Swollen microgel

Swollen gel deposition

Cement Wall

Low pH

High pH

             2 . Neutralization reaction between polymer solution and cement surface causing the pH to increase.

             3.   The pH increase initiates the swelling of microgel resulting in the thickening of the gel  

Figure 2. pH-triggered gelling mechanism in cement fracture.

Our goal is to efficiently place/inject the polymer dispersion into the cement micro fractures and effectively seal off leakage pathways.

Figure 3. Gel yield stress increase as pH increase.

•  Breakdown pathway development is due to the contraction of gel network caused by the presence of calcium cations from the cement

•  Chelating agent pre-treatment can successfully remove calcium cations and inhibit Ca-polymer syneresis

Methodology

After 1 day After 2 days After 4 days

Figure 4. Contraction of swollen gel network by Ca++ ion (syneresis).

Figure 5. Temporary blockage and breakthrough of unstable syneresed gel.

Mineral  Oil  

Pre-treatment Chemicals

DI Water

Pump

Cor

e

Effluent  Collector  

Pressure Transducer

1.  The cement fracture is pre-soaked with a small bank of chelating agent to remove Ca++ from a thin layer of cement

Figure 6. Syneresis inhibiting pre-treatment setup.

Results

2.  Subsequent polymer gelant injection allows formation of the calcium-free yield-stress gel on the fracture surface.

3.  The core is shut in for various durations to allow polymer to react with the cement and to form flow-blocking gel.

Figure 7. Gel resistance to pressure buildup in cement fracture.

4.  DI water/acidic brine is used as holdback fluid and pumped at constant flow rate for a steady pressure buildup.

5.  The maximum pressure before holdback fluid breakthrough is recorded and translated as holdback pressure gradient (psi/ft) to determine the resistance of gel.

•  The holdback pressure gradient greatly improved for pre-treated cement due to the removal of Ca++

•  Sodium Triphosphate (Na5P3O10 ) pre-treated cement has been proven to have the best performance in both polymer injectivity and pressure holdback

Figure 8. Summary of holdback pressure gradients for cement with/without pre-treatment.

Figure 9. Formation of “bubbles” after Na5P3O10 pre-treatment in reacted polymer gel in cement fractures

over various shut-in times.

Conclusions

Acknowledgements The authors would like to acknowledge the Department of Energy (DOE) for the financial support of this project (Award No.: DE-FE0009299) at the Center for Petroleum Engineering at The University of Texas at Austin.

•  pH-trigger polymer gelant has desirable yield stress in holding back pressure and is effective at stopping leaks in cement fractures.

•  Chelating agent pre-treatment can successfully

remove calcium cations and inhibit the unstable gel formed by Ca-polymer syneresis.

•  Results from various shut-in time implies that Na5P3O10 reaction and gel development reach completion around 2-weeks time and continues to mature/dehydrate forming a strong gel.

•  The calcium removal happens quickly and effectively with pre-treatment time as short as 10 minutes.

(a)

(b)

(c)

Figure 10. Breakthrough of acidic brine after 1 hr polymer shut-in: (a) polymer flow path during polymer injection. (b) initial breakthrough. (c) increased dissolution of polymer gel by acidic

brine some time after breakthrough.

Figure 11. Bench test as analogy to field application in which we aim to achieve effective seal in the cement sections within the impermeable layer.