Generation, Migration, Accumulation and Recovery of ... files/pdfs/documents/techn… · •...

School of Applied Geosciences

www.emr.rwth-aachen.de

Alexandra Amann-Hildenbrand1 & Amin Ghanizadeh2

Bernhard M. Krooss1, Christopher R. Clarkson2

1 Energy and Mineral Resources (EMR) Group, RWTH Aachen University

2 Tight Oil Consortium (TOC), University of Calgary

Generation, Migration, Accumulation and

Recovery of Hydrocarbons in Tight Rocks:

Insights from Laboratory Observations

March 19, 2019

Hyatt Hotel, Imperial Ballroom

Europe

Aachen

Introduction

Petrophysics Lab (Aachen)

❑ Long history in reservoir &

caprock characterization

❑ Advanced multidisciplinary

research

❑ Experiments/Modeling

TOC Lab (Calgary)

❑ What is the role of fossil fuels

in Germany?

❑ Germany’s energy transition

concept

❑ Implication for research

topics in Aachen?

Germanys energy consumption (12/2018)

90% imported

94% imported

97% imported

Lignite

Nuclear

others

Hard coal

10.1% Gas

Renewables

www.bmwi.de/

Germanys energy consumption (12/2018)

90% imported

94% imported

97% imported

Lignite

Nuclear

others

Hard coal

10.1% Gas

Renewables

www.bmwi.de/

Research topics in Aachen

❑ Hydrocarbon generation & migration & accumulation (80s-90s)

❑ Unconventionals (coalbed methane, gas shales, tight sandstones)

❑ Subsurface storage

o Nuclear waste

o Carbon capture & storage (CCS)

o Hydrogen storage

Capabilities at TOC (Calgary) and Petrophysics Lab (Aachen)

❑ Advanced core and cuttings analysis

• Reservoir characterization

• Fundamental hydromechanical fluid storage and transport processes

• Fluid-rock interaction

• Enhanced hydrocarbon recovery evaluation

❑ Equipment

→ Triaxial fluid flow & rock mechanical cells, high/low-pressure sorption cells

→ Closed/Open pyrolysis systems, gas chromatographs, etc

❑ Never expect one single technique to be the best and most valid

❑ “Failed” experiments might have hidden value (be smart)

❑ Individual and flexible combination of different tools

→ Different boundary conditions (i.e. different fluids, techniques, etc)

→ Different scales (plugs, cuttings, slabbed cores, etc)Final goals

o Understanding the fundamentals of controlling mechanism

o Integration of lab data into field-scale modeling/simulation

❑ Multiple scales within space and time

millimeters

Matrix with fine-scale

laminations and

fractures

0.5 mm

STYLIOLINA

micrometers

Matrix with

interspersed organic

and inorganic matter

nanometers

Nanopore structure

of organic and

inorganic matter

❑ Complex series of physico-chemical processes

Continuum Scale Description Fundamental Mechanisms

meters

Reactivated natural

fractures

Induced

hydraulic

fracture

centimeters

Natural

fracture

Matrix

(Clarkson et al., 2016; JNGSE 31, 612-637)

Advanced characterization methods at all scales are critical for:

• Primary and enhanced hydrocarbon production

• Subsurface storage

Introduction

Montney equivalent outcrop (Hood Creek)

Image Courtesy: Mason MacKay

Reservoir quality, rock mechanical properties, composition and

fluid-rock interaction are variable along the laterals.

Introduction (continued)

❑ Petrophysical properties (e.g. porosity/permeability)

❑ Geomechanical properties (e.g. Young’s Modulus, Poisson’s Ratio)

❑ Composition/Fluid-Rock interaction (e.g. wettability, contact angle)

1000 m+

55555 ,,,, hiPEk 44444 ,,,, hiPEk 33333 ,,,, hiPEk 22222 ,,,, hiPEk 11111 ,,,, hiPEk

Property variation along laterals

Example: multi-fractured horizontal wells (MFHWs)

❑ Highly heterogeneous systems (even at mm/cm-scales)

❑ Only samples typically available are drill cuttings

❑ Commercial techniques sometimes fail to properly characterize

Samples

Frac stagesUpper Zone

Lower Zone

Vertical exaggeration: 3x

Frac stage 1

GR Log

Toe (TD)

9 Successful stages

(Clarkson et al., 2016; JNGSE 36, 1031–1049)

Problem Statement

(Deglint et al., 2017; Scientific Report 7, 4347)

❑ Limited datasets for two/three-phase fluid flow and storage

Incorrect!

Generation, Migration & ExpulsionChanges in mass/volume ratios and composition under stress

Selected Examples/Innovations

Petroleum generation and expulsion

• Temperature ➔ reaction kinetics

• Burial and loading ➔ rock mechanics

• Fluid transport ➔ petrophysics

• Hydrocarbon composition ➔ organic geochemistry

melting ice “compaction” experiment

Transformation of “load-bearing solid” kerogen to a fluid phase

Lias Basin (Posidonia Shale): Volume balance

(Rullkötter et al. 1988; Mann et al. 1991)

TOC, Rock-Eval

and solvent

extraction data

Primary migration and expulsion (shale oil & gas)

• What is the driving force?

• compaction?

• solid/fluid transformation of

• pressure build-up due to

“volume expansion” of OM (in

a static pore system)?

• What are the transport avenues?

• inorganic/organic pore

system?

• What are the changes in OM

volume and pore volume during

petroleum migration & expulsion?

Confined thermal

compaction

experiment

(Hanebeck,

Unconfined thermal

compaction

experiment

(Eseme, 2006)

Thermo-mechanical deformation test

❑ Changes of geochemical characteristics

❑ Mass & volume balance

❑ Compressive strength, modulus of elasticity (Young’s modulus),

maximum axial strain

Ongoing research study

❑ Poro/Perm change upon heating up to 150°C (under stress)

Thermal Stage Temperature Hydrocarbon/OM Type Evolved

As-Received Room Temperature None

S1 150°C Lighter free Hydrocarbon

S2a 380°C Fluid-like Hydrocarbon Residue (FHR)

S2b 650°C Solid Bitumen, Kerogen

Controlled-Atmosphere Furnace (Across International®)

(TOC Laboratory)

Programmable

ESH Rock-Eval: “Artificial” Cuttings

(Ghanizadeh et al., 2018; SPE189787)

1.E-08

1.E-07

1.E-06

1.E-05

1.E-04

1.E-03

0 2 4 6 8 10

Helium porosity (%)

Crushed-Rock Perm (as-received)

Crushed-Rock Perm (after S1 removal)

Crushed-Rock Perm (after S2a removal)

Crushed-Rock Perm (after S2b removal)

rp35 = 10 nm

rp35 = 5 nm

rp35 = 1.5 nm

rp35: estimated from a modified Winland-style correlation (Di and Jensen, 2015)

rp35 = 3 nm

ESH Rock-Eval: “Artificial” Cuttings

Practical Use:

➢ Understanding reservoir quality in presence of lighter & heavier free hydrocarbons

Duvernay Example

❑ Heating Stage: Seeing is believing!

Video Courtesy: K.M. Clarke & C. DeBuhr

❑ ESH cycle was reproduced using SEM heating stage

❑ “Live” imaging of organic/inorganic matter evolution

Image Courtesy: H.J. Deglint

Live Imaging Pyrolysis: Duvernay

Storage propertiesExcess sorption isotherm

& Porosity

- Dry or moist

- Pushing the detection limits

- Stressed

Adsorption isotherms (coals & shales)

CH4 sorption capacity (mmol/g or mol/kg):

• activated carbon (technical sorbent)

• coal

• shaleShales have

comparatively low

sorption capacities

0 5 10 15 20 25 30

Excesssorp

on[mmol/g]

Pressure[MPa]

45°C(0%moisture) 45°C(2.69%moisture)

Mature Shale (TOC = 5.8%, Ro = 2.4%)

moisture-eq.

Gasparik et al. Rev. Sci. Instrum. 84, 085116 (2013)

Effects of temperature and moisture content on CH4 sorption

Standard procedure: 25 MPa,150 °C, particle size: 500-1000 µm, moisture vs. dry

Gaus et al., in preparationStress dependence

❑ Storage capacity (free and sorbed gas phase)

❑ Uptake kinetics (permeability, diffusivity)

Transport propertiesGas permeability

- Moist

- Stressed

Poro-elastic & fluid dynamic effects Fink et al. (2017)

→ New set-up

equipped with

strain gauges

Verification of theory

→ Tests on synthetic porous rocks

→ Completely rigid

0 1000 2000 3000 4000 5000 6000

Effective Stress (psi)

Mean Pore Pressure = 14.9 psi

❑ Stress & hysteresis-dependent propped frac conductivity

Duvernay Example

Detailed application of these data was presented today at:

SPE Duvernay Workshop (March 19-20, 2019; Calgary)

Practical Use:

• Greater constraint on rate-transient analysis (RTA) e.g. flowback modeling

Gasbreakthrough and residual trapping

➢ Estimating relative permeability of intact and fractured rock

0 50 100 150

Time (h)

Downstream Pressure

Upstream PressureI

Theory Experiment (TOC Lab)

Mechanism I: Single-phase liquid flow

Mechanism II: Two-phase gas/liquid flow; controlled by ΔP

Mechanism III: Diffusion

❑ Core/Cuttings: Liquid/Relative Permeability

Selected Examples

(Hildenbrand et al., 2002; Geofluids 2, 3-23)

Montney Example

Nuclear Magnetic Resonance (NMR) flow cell

Additional use of centrifuge data

❑ Pore size distribution

❑ Relative permeability curves

in collaboration with Applied Geophysics and Geothermal Energy Department (Aachen)

➢ Same platform can be used for performing core-based huff-n-puff tests

Injection Soaking Production

Practical Use:

• Evaluation of incremental oil recovery using experimental huff-n-puff

❑ Core/Cuttings: Huff-n-Puff Experiments

Sample preparation and representativeness

How to obtain “representative” sorption/transport data for organic-rich shales/coals?

Photograph: Imperial College, London (S. Durucan)

Epoxy-embedding;

4 injection “wells” with pressure

transducers

Heterogeneous samples with irregular shapes

Objectives:

assessment of connectivity, permeability

anisotropy and storage capacity

Vacuum pump

Valve 3

Valve 2

Pressure transducer

Valve 1

Back pressure regulator

Gas flow meter

Core holder

Injection

Core holderCore holder

Shut-inProduction

Rate-Transient Analysis (RTA) Permeameter

➢ Novel technique for measuring stress-dependent permeability

(Clarkson et al., 2019; Fuel 235, 1530-1543)

Slide courtesy of Atena Vahedian, TOC’s Lab Technician

RTAPK: Examples

❑ Comparison with Pulse-decay Permeability Technique

Advantages:

• Similar boundary conditions as those present in field-scale well-tests

• Two independent estimates of stress-dependent permeability + porosity

• Significantly shorter turnaround than routine tests (e.g. pulse-decay method)

Slide courtesy of Atena Vahedian, TOC’s Lab Technician

Montney Example

Wettability & Surface Properties

❑ Core/Cuttings: Micro-wettability

➢ Novel technique for estimating micro-droplet contact angles and imbibition

rates using environmental SEM

Video courtesy of Hanford Deglint, former PhD student, TOC

150 µmMontney Example

Images courtesy of Hanford Deglint, former PhD student, TOC. (Deglint et al., 2017; Scientific Report 7, 4347)

❑ Core/Cuttings: Micro-scale contact angle

Montney Example

R² = 0.982

0 1 2 3 4 5 6 7 8 9 10

Elapsed Time (s)

Imbibition Rate of Distilled Water Montney Sample (4B Site #2)

Original

Corrected

Linear (Corrected)

Deglint, 2018 (PhD thesis)

❑ Core/Cuttings: Micro-scale imbibition rate

Practical Use:

• Create “wettability maps” for input into pore-scale models for predicting capillary

pressure/relative permeability

• Evaluate fluid imbibition rates and fluid sensitivity for various rock components

Montney Example

Water vapour isotherms: DVS methodology

▪ Dynamic Vapour sorption (DVS)

• gravimetric measurement

• typical sample mass: 50-100 mg

• analytical resolution: 0.0001 mg

• relative pressure: 0-0.99, < ±0.005

• temperature: 10 - 90 °C

SMS DVS ET @ CIM

Sw = 26%

❑ Differences in rate of sorption as function of RH

❑ Rate of sorption is related to diffusivity

❑ Changes in diffusivity = pore (throat) blocking?

❑ Controlling gas transport properties (Pc-driven mobilization of water phase)

Natural Sciences and Engineering Research Council of Canada (NSERC)

TOC Lab (Calgary) Petrophysics Lab (Aachen)

Acknowledgement

Backup Slides

Solvent flow-through extraction under stress

Key questions• Potential fluid pathways

• Distribution of bitumen in the pore system • Accessibility and composition of bitumen • Porosity and permeability evolution

Mohnhoff et al. (2016), Xie et al., (2019)

→ Limited petrophysical information

→ Extraction efficiencies

→ Geochemical changes

Analytical approach

Samples

Frac stagesUpper Zone

Lower Zone

Vertical exaggeration: 3x

Frac stage 1

GR Log

Toe (TD)

9 Successful stages

-100 0 100 200 300 400 500 600 700

Temperature ( F)

(Pc, Tc) of Fluid 1

(Pc, Tc) of Fluid 2

Reservoir Initial P, T

Fluid-in-Place

Permeability/Diffusivity

Nanoindentation/Mechanical Properties

Modified after Mason et al. (2014)

❑ Core/Cuttings: Along-Well Characterization

(Clarkson et al., 2016; JNGSE 31, 612-637)

➢ New experimental setup for estimating liquid permeability and relative

permeability of intact and fractured rock

Designed/Assembled In-House (URTeC 2902898)

Single/Multicomponent gases

▪ He, Ar, N2, CH4, CO2

▪ Lean/Rich gas

❑ Single-Phase Liquid Flow

▪ liquid permeability

→ kabs (oil, brine, fracturing fluid, etc)

❑ Two-Phase Liquid/Gas Flow

▪ gas breakthrough

→ Pc (entry, breakthrough)

→ Pc (snap-off)

→ keff (gas) as function of ΔP

→ krel (gas) as function of ΔP

→ Deff

RTAPK: Data Evaluation

(Clarkson et al., 2019; Fuel 235, 1530-1543)

❑ Core Plugs

▪ Length: 0.1 - 3”

▪ Diameter: 1, 1.5”

❑ Paxial & radial

▪ ˂ 10,000 psi

❑ Pfluid

▪ ˂ 5,000 psi

▪ Any liquid

• brine

• oil

• etc

❑ Multi-purpose high-pressure triaxial system

▪ Matrix/Fracture fluid (gas/liquid) flow

▪ Ultrasonic analysis (Vp, Vs)

150°C 400°C >650°C

S1 S2a S2b

Free HC FHR (Fluid-Like HC Residue) Solid Bitumen

Extended Slow Heating Rock Eval

Standard Rock-Eval

25 °C/min

300 °C – 650 °C

Extended Slow Heating (ESH) Rock-Eval

10 °C/min

150 °C – 650 °C

300°C

650°CAdvantage of ESH Rock-Eval

Capable of distinguishing various hydrocarbon/OM components

• free hydrocarbons (up to 150 °C) – S1

• fluid-like hydrocarbon residue (FHR, 150-380 °C) – S2a

• solid bitumen (380-650 °C) – S2b

Sanei et al., 2015 – IJCG 150-151; 296-305.

ESH Rock-Eval: Concept

Storage & Transport

Rel Perm: Modified Dacy’s Method

Centrifuge Centrifuge

❑ Modified Dacy’s Method

krg: gas phase relative permeability

krl: liquid phase relative permeability

Repeat

Model: Clinical 200

Manufacturer: VWRTM

krl krl

➢ Estimating liquid permeability and relative permeability of intact and

fractured rock

Slide Courtesy of Amin Ghanizadeh

0 10 20 30 40 50 60

Time (h)

Downstream Pressure

Upstream Pressure

Relative Permeability

Effective stress: 2670 psi

Mean pore pressure: 370 psi

ΔPresidual = 88 psi

Selected Examples

Montney Example

Thermal Compaction Test (Posidonia Shale)

0 20 40 60 80 100

Time / [h]

thermal expansion during initial heating phase

original sample: TOC: 10.4 %

Tmax: 428 °C

HI: 745 mg/g TOC

after compaction test: TOC: 7.94%

Tmax: 443 °C

HI: 284 mg/g TOC

• unconfined load test

• 350°C

• 14 kN (22 MPa)

(Hanebeck, PhD thesis 1995)

Rel Perm: Modified Dacy’s Method

❑ Better match with LET Model; higher degrees of freedom (compared to Corey)

❑ Dead oil (experimental) vs. Live oil (modeling) – Mobility (perm/viscosity)

0 20 40 60 80 100

Gas Saturation (%)

krg-Laboratory

kro-Laboratory

krg-LET Model

kro-LET Model

Montney Example

Helium Porosity: 8.8%

Slip-corrected N2 Perm: 0.0046 md

Practical Use:

• Greater constraint on primary and improved oil recovery modeling/simulation

0 500 1000 1500

Time (h)

2-1 (Surfactant A+Tap Water)

1-2 (Surfactant B+Tap Water)

1-1 (Surfactant B+Brine)

4-3 (Surfactant C+Brine)

2-2 (Surfactant A+Brine)

3-2 (Surfactant C+Tap Water)

3-1 (Brine)

4-1 (Field Brine)

4-2 (Tap Water)

Temperature

Temperature: 26.4±0.2 C

Surfactants for EOR: Montney Example

Slide 50

C9 C10 C11 C12 C13 C14 C15 C16 C17 Pr C18 Ph C19 C20 C21 C22 C23 C24 C25 C26 C27 C28 C29 C30 C31 C32

n-Alkanes

original 1-2 2-1 2-2 3-1 3-2 4-1 4-2 4-3

C9 C10 C11 C12 C13 C14 C15 C16 C17 Pr C18 Ph C19 C20 C21 C22 C23 C24 C25 C26 C27 C28 C29 C30 C31 C32

n-Alkanes distribution in different produced oil samples

➢ Corresponds very well with recovery data (inversely)

➢ The higher the recovery; the less the portion of C9-C13

➢ Also good correspondence with (not shown):

o Adamantanes

o Naphthalenes

Surfactants for EOR: Montney Example

Practical Use:

• Understanding fundamental mechanisms of surfactant-based EOR in tight rocks

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