Enhanced Oil Recovery from the Bakken Shale Enhanced Oil Recovery from the Bakken Shale Using Surfactant Imbibition Coupled With Gravity Drainage

09123-09Dongmei Wang

RPSEA Onshore Production Conference: Technological Keys to Enhance Production OperationsApril 10 2012

The University of North Dakota

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April 10, 2012Midland, Texas

rpsea.org

Outline

BackgroundBackground

Objective

Mechanism 

Technology/Methodology

State of Work

W k P2

Work Progress

1. BACKGROUND

(1) Conventional vertical drilling :1953-1987

Natural fractures had poor flow connections with the vertical wells,production rapidly dropped to low values

(2) Horizontal drilling in the upper Bakken Shale:1987-2000:

Borehole instability related problems often arise when drilling weak fissileBorehole instability related problems often arise when drilling weak, fissileshales

(3) Horizontal drilling in the Middle member with some hydraulic(3) Horizontal drilling in the Middle member, with some hydraulicfracturing to routine fracturing: 2000-present:

Wells completed in unconventional plays typically exhibited limited

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Wells completed in unconventional plays typically exhibited limiteddrainage areas and yielded a low oil recovery

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2. OBJECTIVES

► Test the degree of imbibition for available waters indifferent portions of the shale to establish their true wetting state.

► Formulate special surfactant solutions that willFormulate special surfactant solutions that willalter the wettability of the formation. This alteration shouldpromote imbibition of dilute aqueous surfactant solutions andincrease oil displacement from the shale.p

► Exploit gravity for collection and recovery ofthe oil in the system of natural and hydraulic fractures that areconnected to horizontal wells.

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3. MECHANISM

Current depletion mechanism:pLiquid expansion with solution gas expansion provides the driving energy once thepressure falls below the bubble point.

Proposed research:Proposed research:Imbibition process might act as a viable supplement or replacement for the primary

recovery.

Important forces:Gravity (due to oil/water density difference).

Capillary (which we hope to induce and accentuate using wettability alteration).

Osmosis (due to very high salinity of the resident formation water versus less salineinjected water).

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j )

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4. TECHNOLOGY/METHODOLOGY

Temperature The efficiency of the imbibitioni d t i d bTemperature

Water salinityprocess is determined by acombination of capillary,gravity, and viscous forces,and osmosis Capillary-Formation permeability

Imbibition rate

and osmosis. Capillary-controlled imbibition of brineinto the matrix and thegravitational force allowsImbibition rate gravitational force allowssufficiently rapid oil drainageinto the fracture system.

Imbibition6

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4. TECHNOLOGY/METHODOLOGY

As wettability is altered, the capillarypressure changes from negative topositive, and counter-current imbibitionmobilizes more oil. Furthermore, therelative permeabilities and residualsaturations will be changed to provide ahigher oil recovery from the core.

Wettability7

Affect flow behaviory

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4. TECHNOLOGY/METHODOLOGY

**Surfactant–brine phase behavior**Oil brine surfactant phase behavior**Oil-brine–surfactant phase behavior

II(+)

III

III

II(+)PL

M

Cse

Cseu

II(-)

III

P

M

Ph b h i

CselPR

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Phase behavior2012 Dongmei.Wang@engr.und.edu

Windsor, 1954Green & Willhite, 1998

4. TECHNOLOGY/METHODOLOGY

The oil-wet cores with a negative capillary pressure areimmersed in a surfactant solution. Oil displacementimmersed in a surfactant solution. Oil displacementdetermined by the inverse Bond number. For wateralone, the macroscopic inverse Bond number, NB

-1, maybe greater than 1 However if IFT is lowered N -1maybe greater than 1. However, if IFT is lowered, NB

-1maybecome less than 1, and the surfactant solution willdiffuse into the core and change IFT and the wettability.This aqueous invasion into the core drives the oil out.

I f i l T igL

kBN

1

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Interfacial TensionAdibhatla, B., and Mohanty, K.K, 2006

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4. TECHNOLOGY/METHODOLOGY

Determine the potential for surfactant formulations1 Determine the potential for surfactant formulationsto imbibe into and displace oil from shale.

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Promote imbibition while minimizing clay swellingand formation damage.2

Balancing the temperature, pH, salinity, and divalentcation content of aqueous fluids to enhance oil

3q

recovery.

Surfactant formulation Optimization10

Surfactant formulation Optimization

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4. TECHNOLOGY/METHODOLOGY

How much surfactant should be injected?o uc su acta t s ou d be jected

Should the process be well-to-welldisplacement? Or should it be a huff and puffprocess?process?

N i l Si l i11

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Numerical Simulation

5. STATE OF WORK

Task Content Status Actual Date

T k 1 P j t M t PlTask 1 Project Management Plan Completed 04-27-11

Task 2 Technology Status Report Completed 04-27-11

Task 3 Technology Transfer Plan Completed 04-27-11

Subtask 4 1 Surfactant formulation optimization C l t d 08 31 11Subtask 4.1 Surfactant formulation optimization Completed 08-31-11

Subtask 4.2 Wettability experiments Completed 12-31-11

Subtask 4.3 Imbibition experiments 06-30-12 Underway

Subtask 4 4 Phase behavior studies 10 31 12Subtask 4.4 Phase behavior studies 10-31-12

Subtask 4.5 Interfacial tension tests 03-31-13

Subtask 5.1 Ideal model building 09-30-13

Subtask 5.2 Field-scale numerical simulation prediction 2-18-14Subtask 5.2 Field scale numerical simulation prediction 2 18 14

Task 3 Website construction Completed 9-18-11

Task 6 Annual Report (Interim Report for Task 4) 3-18-12 CompletedAnnual Report (Interim Report for Task 4) 3-18-13

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Final Report 3-18-14

6. WORK PROGRESS

Subtask 4.1

Surfactant Formulation Optimization

Subtask 4.2

Wettability Tests

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Core Acquisition

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Core samples from 3 wells of Upper shale and Middle member

Testing Conditions

Bakken Formation crude oil:Hess Oil Well B.L. Davidson 2-11H. The APIgravity was 43.2°API, and oil density 0.82 g/cm3at 23 2°Cat 23.2°C.

Brine water: 15-30 wt% TDS with mol%Brine water: 15 30 wt% TDS with mol% Na+: 87.7, K+: 3.4, Ca2+ : 7.8, Mg2+ : 1.1

Temperatures, °C:23, 60, 90, 110, 120

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23, 60, 90, 110, 120

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Subtask 4.1

Determine the potential for surfactant formulations1 Determine the potential for surfactant formulationsto imbibe into and displace oil from shale.

1

Promote imbibition while minimizing clay swellingand formation damage.2

Balancing the temperature, pH, salinity, and divalentcation content of aqueous fluids to enhance oil

3q

recovery.

Surfactant formulation Optimization16

Surfactant formulation Optimization

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Surfactant samples

Sample Supplier Type

A-6 Tiorco Anionic (1) SulfonatesA 6 Tiorco AnionicC-1 Tiorco AnionicC-2 Tiorco AnionicC-8 Tiorco AnionicS2 Tiorco Anionic

(1) Sulfonates

(2) SulfateS2 Tiorco AnionicS3B Tiorco AnionicS12 Tiorco AnionicS14 Tiorco Anionic17A CorsiTech Amphoteric

(3) Dimethyl amine oxide17A CorsiTech Amphoteric17B CorsiTech Amphoteric58N CorsiTech Nonionic12J CorsiTech AmphotericO332 Shell Chemicals Anionic

(4) Ethoxylates

O332 Shell Chemicals AnionicA771 Shell Chemicals AnionicSS-7593 Oil Chem Nonionic1688 Oil Chem NonionicN969 Oil Chem Unknown

(5) Ethylene glycol butyl ether

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N969 Oil Chem

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Spontaneous Imbibition

Centrifuge Forced injection

Oil f d t b i bibiti t 90°C ith f t t 58N

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Oil forced out by imbibition at 90°C with surfactant 58NWell 3328-H (#16771) (Hess), SPE 145510

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Findings90 C

Surfactant Formulation

Surfactant Concentration,% Alkaline additive,% Salinity,wt% Oil recovery,%

0 1 0 15 8 30

Temperature: 90 C

17Aamphoteric

0.1 0 15 8.30

0.1 0.1 15 10.12

58N, nonionic

0.1 0 30 15.42nonionic 0.05 0.1 30 19.12

S2, anionic0.1 0 30 12.87

0.2 0.25 30 14.05

C1+Ethanol 0.1 0 30 11.13

1688+S3B 0.1 0 30 6.82

Alkaline: NaBO2.4H2O; C1: Linear α-olefin sulfonate; 1688: Ethylene glycol ether; S3B: Internal olefin sulfonate

Significance: For a given surfactant oil recovery can be maximized by identifying the optimal

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For a given surfactant, oil recovery can be maximized by identifying the optimalsurfactant concentration, brine salinity, sodium metaborate concentration, anddivalent cation content.

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Summary

Ethoxylate nonionic surfactant , internal olefin sulfonateanionic surfactants, an amine oxide amphoteric surfactantanionic surfactants, an amine oxide amphoteric surfactantwere more stable at 105−120°C.

Sodium metaborate may help increase alkalinity withoutSodium metaborate may help increase alkalinity withoutprecipitation in the brine.

Ethoxylate nonionic surfactant and an internal olefinsulfonate anionic surfactant were more tolerant of highsalinity and displayed higher oil recoveries at highy p y g gtemperature.

For a given surfactant there is an optimum hardness level

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SPE 145510For a given surfactant, there is an optimum hardness level

Summary

Changing the pH of the surfactant solution may reduceflakingflaking.

Oil recovery can be maximized by identifying an optimalf t t t ti b i li it disurfactant concentration, brine salinity, sodium

metaborate concentration, and divalent cation content.

C f t t iti l h t ti l fCo-surfactant compositions also show potential forincreased oil recovery.

Kinetic stability of surfactants need to be considered infuture work.

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SPE 145510

Subtask 4.2

Establish the true wetting status from the different1 Establish the true wetting status from the differentportion of Bakken Formation before surfactantinduced.

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2 Identify if the wettability can be altered usingsurfactant formulations.

3 Determine the potential of surfactant formulationsto imbibe into and displace oil from shale.

Wettability Tests22

Wettability Tests

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Methodologies and Results

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Spontaneous imbibition and forced injection

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Summary

Bakken shale cores were generally oil-wet or intermediate-wet (beforeintroduction to the surfactant formulation).

Surfactant formulations tested consistently altered the wetting state ofBakken cores toward water-wet.

The surfactants used consistently imbibed to displace significantlymore oil than brine alone.

Positive results were generally observed with all four surfactants: 17A,58N, S2, and C1.

From our work to date, no definitive correlation is evident in surfactanteffectiveness versus (1) temperature, (2) core porosity, (3) whether thecore was from the Upper Shale or the Middle Member and (4) whether

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core was from the Upper Shale or the Middle Member and (4) whetherthe core was preserved (sealed) or cleaned prior to use.

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Acknowledgments

We thank:Ron Matheney, Nels Forsman,Julie LeFever, Salowah

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Ron Matheney, Nels Forsman,Julie LeFever, SalowahAhmed, Hong Liu

Thank you!

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