Case Study of Polymer Flooding a Heavy Oil in the Tambaredjo Field, Suriname 2008 till now

Transcription

1 REGIONAL ASSOCIATION OF OIL, GAS & BIOFUELS SECTOR COMPANIES IN LATIN AMERICA AND THE CARIBBEAN Case Study of Polymer Flooding a Heavy Oil in the Tambaredjo Field, Suriname 2008 till now Kathleen Moe Soe Let StaatsolieMaatschappijSuriname N.V. 86 th ARPEL Experts Level Meeting (RANE) Management of Reservoirs October 6-7, 2014 Buenos Aires, Argentina Overview of Content Introduction From Screening to Pilot Overview of Reservoir Studies Pilot Implementation Main challenges & learnings Expansion Plans A Look Into the Crystal Ball 2 1

2 Introduction Tambaredjo Field 3 Introduction Tambaredjo Lithology Unconsolidated Sands Depth 900-1,400 ft Net thickness 5-45 ft Porosity 33-40% (log derived) Permeability Darcies Heterogeneity (V DP ) ~0.78 Temperature 100 F Initial reservoir pressure psi HeavyOil API Live Oil Tr 650 1,100 cp Primary Recovery ~30% OOIP 4 2

3 From Screening to Pilot WHY POLYMER FLOODING 5 From Screening to Pilot 6 3

4 Introduction Pilot Area: 3 injectors (inverted 5-spot) 7 Overview of Reservoir Studies Preliminary Lab Studies o Flow-through experiments (sandpacks Ottawa sands) o Coring and core analysis, including reservoir condition coreflooding experiments (with polymer) Reservoir Characterization Studies o Static model of pilot area Reservoir Simulation o Optimization of polymer injection initial flooding pattern (3 injectors & 10 off-set producers) o Optimal development scenarios Phase I Expansion 6 additional injectors & 32 producers Polymer Stability and Retention Alternative Polymers 8 4

5 Pilot Implementation Main Challenges& Learnings Realized incremental oil recovery as of July 2014 is 3% OOIP of pilot area. Good injectivity(spe ). Injection viscosity (40 cp85 cp125 cp). Good pressure response. Minimal polymer degradation (SPE ). Polymer retention low (SPE ). Polymer plant downtime < 3%. 9 Pilot Implementation Main Challenges& Learnings NEW ANAEROBIC SAMPLING METHOD (SPE164121) 1. Polymer stability tests pointed out severe degradation (18 to 3 million daltons). 2. Visual inspections at wellheads showed viscous fluid. 3. Several samples analyzed at different time steps introduction of more oxygen (with iron content in polymer solution) caused higher degradation in time. 4. Improved on-site sampling 10 5

6 Pilot Implementation Main Challenges& Learnings Total injection about 45% of the pilot pore volume (PV): 24% of pilot pattern flooded. 21% moved outside pilot area. First oil bank response already observed. Recent indications of pending oil cut response in a few wells probably due to injection of higher polymer viscosity. Some producers with possible positive skin. 11 Production response vs PV injected 1M Oil rate (bbl/d) ,05 0,1 0,15 0,2 0,25 0,3 0,35 0,4 Injected volume (PV) 1M051 1M09 1N06 1M

7 1I25 1I25 Pressure Oil Cut response response

8 Realized incremental oil production 15 Expansion Plans Commercial Expansion 27 Additional Injectors Planned 16 8

9 A Look Into the Crystal Ball- Expectations Optimal development plan for polymer flooding expansion area o Optimal well locations o Optimal polymer injection strategies o Cost effective polymer Possible upside commercial expansion: three-fold oil production rate Simulated oil production rate forecasts Phase I Expansion Area 125 cp& various rates