07 Production Optimization Feb08

Reservoir Management

Production Optimization

DELIVERING KNOWLEDGE. DEVELOPING COMPETENCE. 1 1

© 2008 PetroSkills LLC, All Rights Reserved

Reservoir Management Pyramid Recovery Optimization Production Monitoring Field Implementation

Development Planning

Reservoir Characterization

Set the Strategy – What Value to Maximize

Reservoir Management Production Optimization © 2008 PetroSkills LLC, All Rights Reserved

7.2

Production Optimization • Target Oil (and Gas) • Residual Oil in the Flooded Region – Target for EOR processes

• Remaining Oil in the By-Passed Region – Target for improved conformance (sweep)

Reservoir Management Production Optimization © 2008 PetroSkills LLC, All Rights Reserved

7.3

Causes for Low Conformance 1.

Vertical Heterogeneity—severe capacity contrast between layers, presence of inter-connected fractures, natural or induced faults, compartments, and lineations

2.

Areal Heterogeneity—anisotropy, well pattern, well spacing, well location with respect to structure, stratigraphy, and proximity of fluid-fluid contacts

3.

Well completion and perforation philosophy with respect to permeability profile, water and gas saturation distributions, and proximity of fluid-fluid contacts

4.

Gravitational segregation of fluids due to density contrast Reservoir Management Production Optimization © 2008 PetroSkills LLC, All Rights Reserved

7.4

Options to Improve Conformance • Infill Drilling • Pattern Rotation (Realignment) • Horizontal and Multilateral Wells • Conformance Improvement

Reservoir Management Production Optimization © 2008 PetroSkills LLC, All Rights Reserved

7.5

Why Infill Drilling? • Enhance Hydrocarbon Recovery (and Profit) From Your Reservoir by Decreasing Well Spacing • Contact Isolated Compartments • Increase Sweep Efficiency • Increase Injection Processing Rates • Usually Some Degree of Interference With Existing Wells

Reservoir Management Production Optimization © 2008 PetroSkills LLC, All Rights Reserved

7.6

General Comments on Well Spacing • Homogenous Reservoirs: – Additional wells accelerate production – No general correlation between recovery efficiency and well spacing – Look for economic optimum – Meet market requirements – Protect against competitive drainage

• Heterogeneous Reservoirs: – Additional wells can connect more reservoir volume and improve recovery

• Injection Projects: – Inter-well pressure limitations can determine spacing

Reservoir Management Production Optimization © 2008 PetroSkills LLC, All Rights Reserved

7.7

Infill Drilling in Oil Reservoirs • Barber (JPT, August 1983) Evaluated Infill Drilling Success in 9 Fields in Texas, Oklahoma and Illinois – Well spacing decreased from 40 acres to 20 and eventually 10 acres per well – Projects added 60.8 MMBO of new reserves from 870 wells – Increased recovery from the new wells was between 56 and 100 percent of the infill well production – Where quoted infill drilling was expected to increase ultimate recovery by 4-8 % of OOIP

• Wu et al (SPE 19783, 1989) Statistically Evaluated Infill Drilling Programs in 25 Waterflooded West Texas Carbonate Reservoirs (14 Clearfork, 11 San Andres) – For the Clearfork reservoirs the median increase in ultimate recovery due to infill drilling was 7.8 % OOIP – For the San Andres reservoirs the median increase in ultimate recovery by infill drilling was 11.4 % OOIP Reservoir Management Production Optimization © 2008 PetroSkills LLC, All Rights Reserved

7.8

Infill Drilling in Gas Reservoirs • Due to Low Viscosity Gas Wells Can Cause Pressure Drops at Distances Well Beyond Their Apparent “Drainage Areas”. • Rate Forecasts for Infill Drilling Should Always Factor in Some Degree of Interference With Existing Wells. • Degree of Interference Best Determined by Simulation • Infill Drilling in Low Permeability (< 0.1 md) Reservoirs Usually Attractive – Can increase “ultimate recovery” by accelerating gas production into an economic time frame (50 years vs 200+) – Will still see interference in homogeneous reservoirs – just takes longer to show up

Reservoir Management Production Optimization © 2008 PetroSkills LLC, All Rights Reserved

7.9

Infill Drilling Reserve Growth vs Rate Acceleration An Example Infill Drilling Study h = 30’ Pi = 8000 psia PhiHC = 0.07 Xf = 300’ FCD = 0.5 (parent well) k = 0.04 md Xf = 500’ FCD = 5 (infill wells) T = 250 F 640 Ac OGIP = 18830 MMscf Produce parent well at 2000 psia WHP initially. Reduce WHP by 500 psi every 2 years. After 10 years, hold constant at 350 psia WHP. Produce all infill wells at 350 psia WHP. EUR, MMscf

Time to EUR, yr

Res Growth

Cum @ 50 yr

Spacing

Start Year

640 ac

0

13538

200

0

7573

320 ac

10

14775

98

1237

12296

160 ac

12 & 14

15552

48

777

15552

90 ac

16 & 20

15653

37

101

15653

Reservoir Management Production Optimization © 2008 PetroSkills LLC, All Rights Reserved

7.10

Reservoir Factors Promoting Infill Drilling • Geologic complexity – Faults – Permeability variations – Lateral discontinuities

• Low permeability • Stress sensitive permeability • Factors that limit effective stimulations • Thick pay

Reservoir Management Production Optimization © 2008 PetroSkills LLC, All Rights Reserved

7.11

Areas to Evaluate for Infill Drilling • Wells With Shallow Declines – Also look at benefits of workovers and facilities enhancements

• Areas Where Volumetric OOIP or OGIP >> Performance Based Values – – – –

Must understand the reason for the discrepancy Bad volumetric estimate? Material balance pressures incorrect? Geologic data consistent with compartments?

Reservoir Management Production Optimization © 2008 PetroSkills LLC, All Rights Reserved

7.12

Pattern Rotation • Align Injection Patterns up With Preferred Permeability Trends • Requires Some Flexibility in Initial Pattern design – Inverted 9-spot pattern ideal if sufficient injectivity can be maintained initially

Reservoir Management Production Optimization © 2008 PetroSkills LLC, All Rights Reserved

7.13

One Possible Conversion: 9-spot to Line drive

Reservoir Management Production Optimization © 2008 PetroSkills LLC, All Rights Reserved

7.14

Horizontal and Multilateral Wells • Increase Rates – – – –

Thin reservoirs Tight reservoirs Viscous oils Encounter natural fractures

• Reduced Water and Gas Coning • Reduced Sand Production • Improved Areal Sweep • Accelerated Recovery • Reduced Investments and Operating Costs Reservoir Management Production Optimization © 2008 PetroSkills LLC, All Rights Reserved

7.15

Basic Multilateral Configurations

Intersect fractures, reduce flowing friction pressure

Commingle horizons, improve productivity

Illustration from Oil Field Review, Schlumberger (Autumn 2002)

Reservoir Management Production Optimization © 2008 PetroSkills LLC, All Rights Reserved

Shallow low pressure or heavy oil sands 7.16

Multilateral Well Junction Classifications

From Oil Field Review, Schlumberger (Autumn 2002)

Reservoir Management Production Optimization © 2008 PetroSkills LLC, All Rights Reserved

7.17

Zuata Area of the Faja Heavy Oil Belt

From Oilfield Review, Schlumberger (Autumn 2002)

Reservoir Management Production Optimization © 2008 PetroSkills LLC, All Rights Reserved

7.18

Types of Multilaterals Used in the Faja Area

From Oilfield Review, Schlumberger (Autumn 2002) Reservoir Management Production Optimization © 2008 PetroSkills LLC, All Rights Reserved

7.19

Single Laterals vs. Multilaterals – Zuata Area

From Oilfield Review, Schlumberger (Autumn 2002) Reservoir Management Production Optimization © 2008 PetroSkills LLC, All Rights Reserved

7.20

Conformance to Improve Areal Sweep • Targeting Wells for Bypassed or Slow Moving Hydrocarbons • Maintaining IWR Balance – Reservoir and individual patterns

• Re-directing Injection • Producing Shut-in Wells • Producing High WOR and GOR Wells • Adding Artificial Lift • Upgrading Surface Facilities to Accommodate Increased Volumes Reservoir Management Production Optimization © 2008 PetroSkills LLC, All Rights Reserved

7.21

Conformance to Improve Vertical Sweep • Perforate All “Pay” • Profile Control in Producers and Injectors • Plugging High Permeability Thief Zones / Fractures • Producing All Layers to High WOR • Selective Stimulation of Low Permeability Layers • Injection Rate/Pressure Adjustments to Maintain Production From High WOR Wells • Reducing Gathering System and Wellhead Pressures Reservoir Management Production Optimization © 2008 PetroSkills LLC, All Rights Reserved

7.22

Foam Block Against Gas Coning / Cusping 1) Injection of surfactant solution in completion brine

2) Initial foam generation by chase gas injection

Gas

Gas

Foam Surfactant

Surfactant Oil

Oil

3) Further foam generation by surfactant alternated gas injection

4) Foam blocking state Gas

Gas

Surfactant Foam

Gas

Oil

Foam block

Oil

Reservoir Management Production Optimization © 2008 PetroSkills LLC, All Rights Reserved

7.23

Targeting By-Passed Oil With Existing Wells • Injecting Gas in a Water Drive or Waterflooded Reservoir May Contact Oil That Has Been ByPassed Due To: – Structural location above highest well “attic oil” – Water underrunning – Water running above discontinuous shale lenses • Oil shielded below the lens

– Overall reservoir heterogeneity

Reservoir Management Production Optimization © 2008 PetroSkills LLC, All Rights Reserved

7.24

Enhanced Oil Recovery (EOR) Process • Minimize retentive capillary force • Changing rock wettability • Eliminate retentive capillary force • Lower mobility ratio between oil and displacing fluid • Promoting increased contact

Reservoir Management Production Optimization © 2008 PetroSkills LLC, All Rights Reserved

7.25

Enhanced Oil Recovery Processes • Thermal: – – – –

• Miscible:

Hot Water Flooding Steam (Soak) In-situ Combustion Electrical Heating

– CO2 – Enriched Hydrocarbon Gas – N2

• Chemical: – Surfactant, Caustic – Polymer (& In-depth plugging) – Micro-organisms Reservoir Management Production Optimization © 2008 PetroSkills LLC, All Rights Reserved

7.26

Reported US EOR Projects

Oil & Gas Journal April 17, 2006

Reservoir Management Production Optimization © 2008 PetroSkills LLC, All Rights Reserved

7.27

Reported US EOR Production

Oil & Gas Journal April 17, 2006

U.S. Oil Production in 2005 – 6.83 x106 stb/d

Reservoir Management Production Optimization © 2008 PetroSkills LLC, All Rights Reserved

7.28

EOR Projects Outside the U.S. • Canada – Steam, combustion HC miscible, CO2 – Total EOR Production about 295,000 bpd (3x106 bpd total)

• Indonesia – Duri field, Sumatra 220,000 bpd steam flood

• Other projects in China, Columbia, India, Mexico, Trinidad, Turkey, Venezuela • New interest in Europe for injection of CO2 from industrial plants injection as a means of sequestration Reservoir Management Production Optimization © 2008 PetroSkills LLC, All Rights Reserved

7.29

Benefits of Thermal Processes • Increased temperature reduces oil viscosity • Reduced viscosity increases flow rates – often to the point of now being economic. • Steam reduces Sor due to distillation. • Adds Pressure to system allowing more driving force.

Reservoir Management Production Optimization © 2008 PetroSkills LLC, All Rights Reserved

7.30

Hot Water & Steam Flooding

viscous oil

hot water injection well

production well steam viscous oil

Reservoir Management Production Optimization © 2008 PetroSkills LLC, All Rights Reserved

7.31

Steam flooding Impact on Reservoir / Stability / Sweep:

Steam Injection: - Quality - Temperature (related to pressure) - Thermal cement, insulation

- Use of horizontal wells - Fluid compatibility (scale, asphaltenes, H2S) - Reservoir characterization, data gathering - Steam override, fingering? Production: - Steam breakthrough - Pump limitations - Well geometry

Steam Hot Oil

Cold Oil Oil Mobility Improvement: - Heated zone only - Drive, pressure gradient

Lower Residual oil (Sor< 5%): - Phase behaviour, Distillation

Enhancements: Better distribution of injected steam Soak: Alternating steam injection / oil production used also to “manage” steamfloods Foam: Add surfactants to injected steam Reservoir Management Production Optimization © 2008 PetroSkills LLC, All Rights Reserved

7.32

Multilaterals and SAGD

Typical steam assisted gravity drainage (SAGD) well configuration in Athabasca Oils Sands (length of horizontal sections 500 – 750 meters)

From Oilfield Review, Schlumberger (Autumn 2002) Reservoir Management Production Optimization © 2008 PetroSkills LLC, All Rights Reserved

7.33

In-Situ Combustion

burn front

injection well air (& steam water)

combustion gases

production well viscous oil

steam condensation vapors

Reservoir Management Production Optimization © 2008 PetroSkills LLC, All Rights Reserved

7.34

The Concept of Miscibility • Two fluids are miscible when they can be mixed together in all proportions and the mixture remains as a single phase. Gasoline and Kerosene • No Interfacial Tension (No Interfaces)

Reservoir Management Production Optimization © 2008 PetroSkills LLC, All Rights Reserved

7.35

Residual Oil Saturation, %PV

Reduction in Residual Oil Saturation

Capillary Number, Uμ/σ Reservoir Management Production Optimization © 2008 PetroSkills LLC, All Rights Reserved

7.36

The Miscible Displacement Process • Displacement Efficiency Increased to Almost 100% of the Contacted Volume. • Miscible Displacement Process has Same (or Worse) Concerns as Immiscible Displacement with: – Vertical sweep efficiency – Areal sweep efficiency

• Alternating Water Injection Helps Control Mobility Reservoir Management Production Optimization © 2008 PetroSkills LLC, All Rights Reserved

7.37

Types of Miscibility • First-Contact – Always single phase with reservoir oil – Propane – LPG – VERY EXPENSIVE

• Multiple-Contact – Initially forms two phases with reservoir oil – Miscibility generated over multiple contacts and mass transfer between injected solvent and reservoir oil – Most miscible injection projects use multiplecontact fluids Reservoir Management Production Optimization © 2008 PetroSkills LLC, All Rights Reserved

7.38

Miscible Flooding Limitations • Pressure / Composition Range Where Miscibility Can be Generated – Minimum pressure increases with reservoir temperature – Higher pressure required for injection gases with large amounts of nitrogen or methane

• Solvent Availability

Reservoir Management Production Optimization © 2008 PetroSkills LLC, All Rights Reserved

7.39

Chemical Methods • Surfactant and Alkaline Flooding – Reduce interfacial tension between water and oil – Lower Sor – Surfactant economics difficult due to high costs

• Polymer Injection – Added to water to increase viscosity and lower mobility ratio – Injected as a blocking agent to modify vertical sweep

• Chemical Methods Not Widely Used Compared to Thermal or Miscible Solvent Processes Reservoir Management Production Optimization © 2008 PetroSkills LLC, All Rights Reserved

7.40

Surfactant Flooding Waterflood

Displacement Transition Zone

Postflood Residual Saturation

Surfactants in reservoir

Displacement Transition Zone

Postflood Residual Saturation

Reservoir Management Production Optimization © 2008 PetroSkills LLC, All Rights Reserved

7.41

Polymer Flooding Water Injection Production

Production

Water & Polymer Injection Production

Production

Reservoir Management Production Optimization © 2008 PetroSkills LLC, All Rights Reserved

7.42

Selecting an EOR Process • Can Make First Pass Based on Technical Screening Criteria – Oil viscosity – Reservoir depth (related to pressure) – Reservoir permeability

• Final Selection Requires Thorough Study and Economic Evaluation

Reservoir Management Production Optimization © 2008 PetroSkills LLC, All Rights Reserved

7.43

Viscosity Ranges for EOR Methods

Reservoir Management Production Optimization © 2008 PetroSkills LLC, All Rights Reserved

7.44

Depth Ranges for EOR Methods

Reservoir Management Production Optimization © 2008 PetroSkills LLC, All Rights Reserved

7.45

Permeability Ranges for EOR Methods

Reservoir Management Production Optimization © 2008 PetroSkills LLC, All Rights Reserved

7.46

Low Salinity Water Injection SPE 93903* (2005) • Injection of Low Salinity Water Appears to reduce Sorw • Experimental Studies – Core floods with North Sea oil • Increased oil recovery 10-40%

– Log-inject-log test Middle East reservoir • Reduced Sorw 25-50%

– 4 single-well chemical tracer tests Alaskan North Slope • Increased waterflood recovery by 8 – 19% (6-12% OOIP) * P.L. McGuire et al, BP Alaska Reservoir Management Production Optimization © 2008 PetroSkills LLC, All Rights Reserved

7.47

Low Salinity Water SPE 102239 (2006) • Process Appears to Alter Reservoir Wettability to More Water-Wet • Process Lithology Dependent – Only Demonstrated in Clastics – Recovery Benefit Increases With Abundance of Some Clays

• Requires Substantial Change in Water Salinity – Consistently < 10% of Connate Salinity – Probably < 25% or 5000 ppm absolute threshold

Reservoir Management Production Optimization © 2008 PetroSkills LLC, All Rights Reserved

7.48

EOR Projects Require More Attention • Need Detailed Reservoir Description to Evaluate Heterogeneity • Pilot Testing – Staged Implementation • Expanded Reservoir Surveillance Program to Ensure Efficient Use of Injection Fluid • Up-front Invesments for New Facilities and Injection Fluid Hurt Economics • Operating Costs Will Also be Higher

Reservoir Management Production Optimization © 2008 PetroSkills LLC, All Rights Reserved

7.49