Building an Enhanced Oil Recovery Culture to Maximise Asset Value. Marco Rotondi Stavanger, 28 th April 2015

Transcription

1 Building an Enhanced Oil Recovery Culture to Maximise Asset Value Marco Rotondi Stavanger, 28 th April 2015

2 Building an Enhanced Oil Recovery Culture - Agenda 1 Introduction 2 Challenges & Solutions Time to Market Costs 2.3 Mindset 3 Building an Enhanced Oil Recovery Culture: Action Plan 4 eni Successful Case Histories 5 Conclusions 2

3 Meeting Future Production Demand Introduction Million Barrels Per Day Global oil demand Deepwater & complex environment Unconventional IOR 0 Natural depletion % 8% 24% Enhanced Oil Recovery Miscible Gas Injection & WAG Thermal Methods Chemical Injection Microbial Methods & Others Source: IEA World Energy Outlook

4 Projects Time to Market Challenges Faster Deployments Y1 Y3 Y4 Y5 Y6-8 Screening Phase Lab Analyses & Simulation Pilot well scale Interwell Pilot Test Full Field Implementation WA SWCTT (Jan 2014) NA Polymer Plant (2014) NA SWCTT (Aug 2014) NA Polymer Plant (2015) OG TM IPSE in-house labs Log-inj-log SWCTT Standard procedures Strategic contracts Monitoring best practices APA for Streamlines High Resolution Simulator Screening Phase well Lab Analyses & Simulation Interwell Pilot Test Full Field Implementation From a sequential to a quicker parallel approach 4

5 Screening Tool for Optimal Techniques & Analogues Challenges In house tool for quick screening phase and analogues evaluation CO 2 Immiscible CO 2 Miscible WAG CO 2 Miscible HC Miscible WAG HC Miscible N 2 Miscible Polymer Surfactant Algorithm searches for analogues 1 within database 2 Optimal Techniques 3 List of references Magnus polymer surfactant CO2 MISC WAG CO2 MISC HC MISC WAG HC MISC WAG HC IMM 1) Development and Testing of Advanced Methods for the Screening of Techniques EAGE IOR Symposium, April ) SPE A New Bayesian Approach for Analogs Evaluation in Advanced Screening EUROPEC, June 2015

6 Challenges Understanding & Reproducing Mechanisms Study the past if you would divine the future 1 Production Data Analysis for 4 3D simulation Core Scale Coreflood N.1: High and Low Salinity Water 50 measured Eclipse STARS Stars Eclipse 100 UTCHEM UTChem Methane Bank oil recovery (%) Material Balance time (hours) Well Scale (SWCTT) Sector & Full Field Scale Streamlines Janus Bifrons Optimizing Waterflood 6

7 Faster & More Accurate Simulations Challenges Deployment of a high resolution simulator for full field simulation Standard Case Study Low permeability oil reservoir Coarse grid: 139x122x56, 200k active cells 46 Horizontal wells and LGR to simulate horizontal wells + hydraulic fractures Outstanding results in terms of simulation time old simulator 15h new simulator 12 min! Pushing the limits Combining HPC2 hardware (30,000 cores, 6000 GPUs) and new simulator to run larger models and capture geological complexity avoiding upscaling eni Green Data Center 240M cell model More accuracy, more simulations, additional time for res eng -> more solutions 1) SPE Deployment of High-Resolution Reservoir Simulator: Methodology & Cases ADIPEC, Nov ) 7 3) SPE Advances in Sim. Tech. for High-Resolution Models: Achievements & Opp. For Improvement - SPE RCSC Sept. 2015

8 Reducing Costs Challenges generally perceived as Oil Production Costs expensive, but comparable Arctic production costs to other oil resource exploitation Heavy Oil Tight Oil UDW Oil Shale GTL CTL Finding & development Conv. Oil costs even lower if projected to 2035 Already Produced MENA Keep an eye on emerging techniques Finding & Development 2035 Low Salinity & Smart Water Considering existing surface facilities & infrastructures and seek for opportunities! Sources: Resources to Reserves, IEA 2013 World Energy Investment, IEA

9 Changing the Mindset A new Culture is still wrongly perceived as a reservoir or lab subject while requires a fully multidisciplinary approach is still considered a technological frontier: We have always done like this should not be exclusive to mature fields requires a strong top management support and long term vision / continuity Reorganization and reinforced team Challenges Growing of a new generation of professionals to generate new ideas and support future implementations start know-how dissemination (WS, webinars, lectures, papers, etc.) Internal guidelines & external collaborations 9

10 Systematic Screening & Opportunity Evaluation Action Plan Many valuable studies and lab tests, very few field applications More time spent to understand how it works rather than if it works in the field A more pragmatic approach was needed to promote applications within the Company Reorganising and rationalising initiatives and R&D portfolio 10

11 Systematic Screening & Opportunity Evaluation Action Plan eni Portfolio Screening Viscosity 0, Optimal Techniques (Strategy revision) Evaluation of additional unconstrained resources & RF High Level Screening Depth (ft) igi mgi ASP Low Salinity Thermal Polymer Oil field Chemical Others Low Salinity Miscible GI & WAG Additional oil Second Level Screening Field by field opportunity evaluation (analogues) eni Field Analog Field Current Dev MGI+WI Current Dev WAG Porosity 14 % Porosity 14 % Permeability 200 md Permeability 243 md Depth 8760 ft Depth 9840 ft MMP 3500 psia MMP 3002 psia Viscosity Viscosity Temperature 185 F Temperature 207 F Initial Pressure Initial Pressure OOIP OOIP RF@2014 RF@2014 5a 5b WAG C Short term opportunity implementations (quick deployment of mature techniques at low cost) Mid term opportunity implementations (building internal competences) 11

12 eni Projects Action Plan iwag Low Salinity + Polymer flooding GI+mWAG CO2 Bright water + low salinity Steam GI GI 1) WAG 2) Polymer 3) Surfactant Polymer 4) Electrical Heating iwag & FAWAG 1) Polymer flooding 2) Low Salinity + Polymer 3) Bright Water Study Pilot Full field implementation Gas injection Thermal Chemical More than 20 new initiatives launched 12

13 Miscible WAG Pushing RF Case Studies North Africa mwag Overview eni Field Analog Field Current Dev MGI+WI Current Dev WAG Porosity 14 % Porosity 14 % Permeability 200 md Permeability 243 md WAG2 Depth MMP Viscosity 8760 ft 3500 psia Depth MMP Viscosity 9840 ft 3002 psia Temperature 185 F Initial Pressure OOIP RF@2014 Temperature 207 F Initial Pressure OOIP RF@2014 Prod1 WAG1 Onshore NA field Developed with WI and mgi Already high RF Nearby field produced by means of WAG New reservoir model Conversion of existing WIs WAG pilot started in Q Impressive results, additional URF of 6% Cost per barrel < 0,5 USD/stb Qoil [STB/d] Prod1 WAG1 Start-up WAG gain Higher than initial plateau 07/ / / / / / / /2016 Improving RF: Never give up! SPE174700, "On the Road to 60% Oil Recovery By Implementing Miscible HC WAG Injection in a NA Field SPE C, Aug

14 Downdip Immiscible WAG Case Studies UK iwag Overview attic oil water path Offshore UK, structurally complex reservoir Developed with WI (high WC = 91%) & crestal offspec gas disposal Change of operatorship in April > APA, Streamline, New 3D Model Water injection is inefficient and attic oil bypassed WAG a feasible solution -> gas from issue to resource WAG Pilot (conversion of two water injectors) foreseen for Q2/ Q Low cost opportunity Additional 2% on URF WAG forecasts Based on pilot results, other 3 water injector wells will be converted to WAG injectors Oil Rate WAG pilot / / / / /2030 From study to pilot in 1y time, low cost per barrel 14

15 Deepwater iwag & Foam Assisted WAG Implementing from Day 1 Case Studies Project Overview Deepwater WA field Production start-up Q (2 prod) iwag start-up Q (2 inj) Analogue field produced by WAG showed gas BT in 1.6 km away producer in 75 dd FAWAG R&D project launched WAG & FAWAG Forecasts WI WAG Foam Assisted WAG is aimed at: Reducing gas mobility in reservoir Increasing sweep efficiency Oil Rate FAWAG WAG Natural Depletion GOR Surfactant Injection WAG FAWAG WAG + 30% on RF wrt natural depletion OP1 WAG2 0.9 years OP1 WAG2 0.5 FAWAG less than 1% on additional recovery but 53% on produced gas WAG 0.03 After 7 years of injection FAWAG Moving to more complex techniques to maximise RF & mitigate subsurface risks 15

16 Maximising Sweep Efficiency in Waterfloodings Case Studies ~ 10-4 m injector producer water oil sand grain Areal sweep efficiency Vertical Sweep Efficiency Microscopic Displacement Exploiting & combining water conformance, low salinity & chemical techniques Water Conformance Polymer Flooding Low Salinity Surfactant Screening Phase Lab Analyses & Simulation Pilot well scale Interwell Pilot Test Full Field Implementation 2 NA Low Salinity Projects Alaska Low Sal + Polymer ME low salinity WA offshore polymer WA SWCTT (Jan 2014) NA Polymer Plant (2014) WA Low Sal+Surfactant SWCTT Tunisia BW (Jan 2014) NA Low Salinity SWCTT (Aug 2014) Egypt Bright Water NA Polymer flooding NA Low Salinity + Polymer flooding 1) SPE Low Salinity Water Injection: eni s Experience ADIPEC, ) SPE17951 SWCTT to Assess Low Salinity Water and Surfactant Processes in West Africa IPTC, ) Low Salinity Waterflooding for : Stochastic Model Calibration and Uncertainty Quantification EAGE IOR

17 Bright Water Pilot & Field Deployment Results Case Studies Thermally activated polymer that improves waterflooding sweep efficiency by in depth reservoir conformance i.e. plugging thief zones and forcing water to follow new paths Ultra mature field, 94% WC Target bypassed oil (inefficient WI by APA & Streamline analysis) 2010: successful pilot test Bright Water Deployment 2013: extension to 2 water injectors and 7 producers Field Results Pilot Extension +130 kstb +60 kstb SPE Thermally Activated Particle Treatment to Improve Sweep Efficiency: Pilot Test Results and Field Scale Application Design in El Borma Field IOR Symposium, April

18 Bright Water Field Deployment Results Case Studies Well A (Pilot) Well B Well C Well D Gain continuing with time, well life extension > 5y, Low treatment costs 18

19 North Africa Polymer Flooding Pilot Case Studies Polymer Plant Polymer Inj Polymer Inj WCT [%] Rate [bbl/day] WCT [%] Liquid Oil Increase in oil production (Well A) WCT reduction (Well B) Polymer Injection: Application in a North African field from Lab Analyses to Project Start-up, OMC

20 North Africa Maximising Waterflooding Efficiency Case Studies Combination of different Technologies 2016 Low Salinity Pilot Q Dispersed WI + Polymer Pilot Q Low Salinity SWCTT 2009 Bright Water pilot Peripheral WI BW Results 30 Low Salinity Results Dispersed WI+ Polymer average Oil Gain +38% Sorw (%) average 14 max 3 months water preflush 1 st polymer slug 3 cp 5 2 nd polymer slug 6 cp in Low Sal Water drive 0 sea water low salinity 1) History Match and Polymer Injection Optimization in a Mature Field Using the Ensemble Kalman Filter, EAGE IOR ) Chemical project for a Giant NA Field, OMC

21 Conclusions Reducing time to market & costs is feasible Conclusions Take advantage of previous experience Be proactive in seeking for opportunities to improve RF (existing infrastructures) Still open technical challenges: Going deepwater Carbonates Standard procedures for monitoring phase Keep investing in people and technology even in this low oil price scenario Promote a more collaborative environment among IOCs, NOCs, SCs and universities Team 21

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