Prepared for: 2015 Carbon Management Technology Conference … [6276331].pdf · 2015 Carbon...

Project Assessment and Evaluation of the Area of Review (AoR) at the

Citronelle SECARB Phase III Site Alabama, USA

Prepared for:

2015 Carbon Management Technology ConferenceSugar Land, TX

JohnRyan MacGregor

Advanced Resources International, Inc.

November 19, 2015

Pressure Transient Response Analysis at the

Southeast Regional Carbon Sequestration

(SECARB) Anthropogenic Test Site near

Citronelle, Alabama



Acknowledgement

This presentation is based upon work supported by the Department of Energy National Energy

Technology Laboratory under DE-FC26-05NT42590 and was prepared as an account of work

sponsored by an agency of the United States Government. Neither the United States

Government nor any agency thereof, nor any of their employees, makes any warranty, express or

implied, or assumes any legal liability or responsibility for the accuracy, completeness, or

usefulness of any information, apparatus, product, or process disclosed, or represents that its use

would not infringe privately owned rights. Reference herein to any specific commercial product,

process, or service by trade name, trademark, manufacturer, or otherwise does not necessarily

constitute or imply its endorsement, recommendation, or favoring by the United States

Government or any agency thereof. The views and opinions of authors expressed herein do not

necessarily state or reflect those of the United States Government or any agency thereof.



Presentation Outline

I. Introduction

II. Study Area Overview and Background

i. Geologic Characterization

ii. Injection History

III. Objectives and Rationale

IV. Empirical Transient Data

V. Hypothetical Pressure Transient Calculations

VI. Preliminary Findings and Next Steps



Pressure Data and Interference Testing

This talk details the efforts to qualitatively assess the

empirical pressure transient data collected from the

SECARB Anthropogenic Test site and place

constraints on reservoir saturations of CO2

Demonstrate non-endangerment

Exhibit new techniques for constraining plume location



Anthropogenic Test Project Background

The SECARB Anthropogenic Test is an integrated Carbon Capture

and Storage project

• CO2 is captured from Southern Company’s Plant Barry

(25 MW slipstream from a 2,657 MW coal-fired power plant)

• A ~12 mile pipeline delivers the

CO2 to Denbury’s Citronelle Oilfield

• The captured CO2 is injected into

the saline bearing Paluxy formation

(~9,500 feet deep)

Approximately 114 thousand metric

tons of CO2 were injected between

8/12 and 9/14



Study Area Background

The Citronelle Oilfield lies atop

the Citronelle Dome

What makes the Citronelle Dome amenable

to CO2 sequestration?

• Well defined reginal geology from oil exploration

and production

• Gulf coast sediments comprise excellent quality

reservoirs

• A proven structural trap

• Structural closure is exhibited in all directions

• The limbs of the dome gently dip ~1°

Plant Barry

Plant

Barry



Storage Site: The Citronelle Oilfield

CO2 is injected at the

Southeast Unit in

Citronelle Oilfield

Structure Map of Ferry Lake Anhydrite

Subsea

Depth

-10,300

-10,350

-10,400

-10,450

-10,500

-10,550

-10,600

-10,650

-10,700

-10,750

-10,800

-10,850

-10,900

• One injection well perforated in multiple zones

in the Paluxy Formation

• Two in-zone observation wells perforated in the

injection zone



Gulf coast sedimentary strata

consist of extensive deposits of

high porosity and permeability

formations

CO2 is injected into the

Paluxy Formation

The field’s target oil

reservoir lies below the

CO2 injection zone

Study Area Stratigraphy

CO2 Injection

Zone

Numerous confining units of

impermeable marine shale and the

Selma Group 2,000+ ft chalk unit

provide confining zones to restrict

CO2 migration



Parameters Unit Value

Mean Permeability, k mD 373

Porosity, φ % 19

D 9-8 Distance from Injector feet 840

D 4-14 Distance from Injector feet 3,500

Pressure psi 4,430

Temperature °F 224

Total Dissolved Solids (TDS) ppm 200,000

Reservoir Characteristics

Site characterization demonstrated satisfactory

geologic conditions for CO2 storage

D 9-7

Injection Well

D 9-8

Observation WellEW

Confining Zone

Injection Zone

Upper

Paluxy

Marine Shale

• The Paluxy SS reservoir is a relatively

continuous saline formation

• Measured permeability up to 4,000 mD

• Porosity range: 4.4% - 26.1%

• Well established overlying cap rock



CO2 Injection History



MVA Elements and Frequency

Continuous Monthly Quarterly Annual

Milestone

(Baseline,

Injection,

Post)

Shallow

Soil flux

Groundwater sampling (USDW)

PFT survey

Deep

CO2 volume, pressure & composition

Reservoir fluid sampling

Injection, temperature & spinner logs

Pulse neutron logs

Crosswell seismic

Vertical seismic profile (VSP)

Experimental

Distributed Temperature Sensing (DTS)

Comparative fluid sampling methods

MBM VSP

Distributed Acoustic Sensing (DAS)

MBM VSP & OVSP Seismic

MVA Method

Frequency

Assure non-endangerment of USDWs

Multiple lines of evidence to confirm CO2 containment



To detail changes in saline reservoir dynamics of the Paluxy Sandstone with the injection of CO2 at the

Citronelle Oil Field and to demonstrate non endangerment of USDW’s

Objective

• Pressure data collected from two, in-zone observation wells

provides a unique opportunity to establish pressure transient

relationships for the reservoir

• Building an empirically validated model will enable the prediction

of reservoir behavior with CO2 injection, facilitating plume

monitoring

Rationale:________________________________________________________________



To detail changes in saline reservoir dynamics of the Paluxy Sandstone with the injection of CO2 at the

Citronelle Oil Field and to demonstrate non endangerment of USDW’s

Objective

• Pressure data collected from two, in-zone observation wells

provides a unique opportunity to establish pressure transient

relationships for the reservoir

• Building an empirically validated model will enable the

prediction of reservoir behavior with CO2 injection,

facilitating plume monitoring

Rationale:________________________________________________________________



Pressure data from two in-zone observation wells were collected from downhole

pressure and temperature gauges deployed in the injection zone.

Pressure data was compared with injection volume and timing to determine

pressure-transient response time.

Methodology

Theoretical response times were calculated using reservoir properties for several CO2

saturations to place constraints on changes in CO2 saturation in the system



Cap Rock

Injection

Well

r

↑P

Pressure rise

observed

Injection begins

Observation

Well

∆p

h

Simple Transient Pressure Model

Time the pulse takes to reach the observation well is a

function of reservoir characteristics



Empirical

Observations



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Cumulative Injection CO2, MMscf

D 9-8 Pulse Testing 840 feet from

injector

Response times recorded from downhole pressure data

• Red diamonds represent CO2 injection starts

• Blue circles represents post-injection water pulse tests

– Water Injection

– CO2 Injection

Legend



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D 9-8 Pulse Testing

A general increase in response time is observed with an

increase in cumulative injected volume for early data

840 feet from

injector

– Water Injection

– CO2 Injection

Legend



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D 9-8 Pulse Testing

9 month

shut-in

The observed drop in response time follows a 9 month shut-

in period

840 feet from

injector

– Water Injection

– CO2 Injection

Legend



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D 9-8 Pulse Testing

Missing

Data

The pulse for the final phase of injection was not observed

due top gauge failure

840 feet from

injector

– Water Injection

– CO2 Injection

Legend



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D 9-8 Pulse Testing

6 month

shut-in

A second shut in period of 6 months yields another pressure

drop

840 feet from

injector

– Water Injection

– CO2 Injection

Legend



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D 9-8 Pulse Testing

4 month

shut-in

A third pressure drop is observed following 4 more months

shut-in

840 feet from

injector

– Water Injection

– CO2 Injection

Legend



Constraining Saturation of CO2 in the Reservoir



Utilizing the measured reservoir properties, the travel time of a pressure

pulse transient from the injection well to the observation well can be solved

by its relationship to dimensionless time (Ahmed, 2010)

𝒕𝑫 =𝛈 𝒕

𝒓𝟐which rearranges to

𝐭𝐃 𝐫𝟐

𝛈= 𝐭

Where:

• η – diffusivity constant - (function of: k, φ, fluid μ, ct)

• tD – dimensionless time

• r – radius of investigation

• t – time

Theoretical Transient Time

Calculations

Calculating this for a range of CO2 saturations will place constraints

on the CO2 saturation of the system



The Hurst-van Everdingen exponential integral (Ei) function for the radial diffusivity

equation is utilized to solve for tD

pr,t = pi −0.141qμ

𝑘ℎ 1 2 −Ei

−1

4tD

1 2 −𝐸𝑖−1

4 𝑡𝐷= pi−pr,t ÷

0.141 𝑞 𝜇

𝑘 ℎ

Theoretical Transient Time

Calculations

The Ei pressure function solution is related to tD

tD is used to solve for the theoretical pressure

transient time at a given reservoir saturation of CO2

𝐭𝐃 𝐫𝟐

𝛈= 𝐭

Rearrange to solve for the Ei pressure

function using known reservoir properties

and ∆pEi

function∆p Reservoir

properties

The transient pressure rise observed at a known

radius for a specific time is a function of the initial

pressure, reservoir properties, and the Ei function

Equation 3.20a,

Slider (1983)

Exponential Integral Function Graph



Exponential Integral Function Graph

Theoretical response times for a pressure transient to

travel from the injector to the observation well were

calculated as a function of CO2 saturation in the reservoir

(a component of η)

Assumptions

• Homogenous distribution of CO2 in reservoir

• Fixed reservoir properties

Cap Rock

Injection

Well

r

↑P

Pressure rise

observed∆p = 0.5 psi

Injection beginsq = 864 bbl/day

Observation

Well

∆p

D 9-8 #2 Example(10% CO2 Saturation)

Fluid viscosity 0.49 cP

Net thickness, h 35 ft

Permeability, k 373 mD

Porosity, φ 19%

Radius, r 840 ft

Diffusivity C, η 1,450,474

System

Compressibility1.75E-5

Pressure gauge

h

𝟏 𝟐 −𝑬𝒊−𝟏

𝟒 𝒕𝑫= 𝟎. 𝟏𝟎𝟗𝟑

tD = 0.24

t = 2.8 hours𝐭𝐃 𝐫

𝟐

𝛈=

Transient Pressure Model



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9

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D 9-8 Pulse Testing

Theoretical response times are calculated from the Ei solution

of the radial diffusivity equation for several saturation levels

840 feet from

injector

40%

CO2

Saturation

30%

20%

10%

0%



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D 9-8 Pulse Testing

40%

CO2

Saturation

30%

20%

10%

0%

Theoretical response times are calculated from the Ei solution

of the radial diffusivity equation for several saturation levels

840 feet from

injector

9 month

shut-in

4 month

shut-in

Missing

Data

6 month

shut-in



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50

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D 4-14 Pulse Testing

Similar observations are made for the D 4-14 well, albeit with lower

saturation values due to larger distance from the injection well

Failed gauges account for the fewer data points

3,500 feet

from injector

10%

7.5%

2.5%

0%

CO2

Saturation

5%



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D 4-14 Pulse Testing

10%

7.5%

2.5%

0%

CO2

Saturation

Similar observations are made for the D 4-14 well(albeit with lower saturation values due to larger distance from the injection well)

Failed gauges account for the fewer data points

3,500 feet

from injector

9 month

shut-in

5%



Preliminary Findings

and Next Steps



The observed pressure data shows that response

time of the pressure transient increases with

increasing volumes of CO2.

The response-time increase may be attributed to an

increase in the system’s overall compressibility

Drops in pressure response time following long, non-

injection periods suggests that CO2 may be going

into solution with the formation water

Preliminary Findings

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