07121-1701_KR Presentations_Working Committee_16 Feb 2010

8/9/2019 07121-1701_KR Presentations_Working Committee_16 Feb 2010

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Working Committee Review

16 February 2010

Research Partnership to Secure Energy for AmericaSub-Contract # 07121-1701


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Outline

Executive Summary

Progress during December 2009 and January 2010

Budget status

Quick review of trapped oil mechanisms and IOR process list

Sent via email 9-December-2009 IOR process analysis

Water injection

Workflow to determine number of applications

Gas injection

Pumping & Artificial lift

Technology transfer

Forward work plan


3/52

Progress Report

December 7, 2009 TAC and Working Committee meetings

Revisions to IOR process evaluation plan agreed 10th December

Little work done last 2 weeks December and 1st week January

Detailed evaluation of Gulf of Mexico water injection performance

Assist preparation of Pennwell DOT conference presentation

Write and submit OTC #20678 titled Can IOR in Deepwater Gulf of MexicoSecure Energy for America

Further research from Houston group on raw seawater injection

Determined workflow for IOR evaluation by process Fine tune database and lock down field/reservoir OOIP and forecasts

Tune Eclipse sector model to match performance of highly compacting reservoir produced bydepletion for use in modeling some IOR processes

Determination of number of applications

Finished water injection IOR except for economics; commenced gasinjection analysis


4/52

Budget Status

$-

$200,000

$400,000

$600,000

$800,000

$1,000,000

$1,200,000

$1,400,000

$1,600,000

1 2 3 4 5 6 7 8 9 10 11 12 13

Cumu

lativeSpend

Months Worked

RPSEA 07121 - 1701: Deepwater IOR

Actual Spend vs. Baseline BudgetBudget Actual Spend

Note: January 2010 is a

preliminary estimated cost


5/52

Overview of Trapped Oil Mechanismsand IOR Process Selection


6/52

Total EUR , 31.6%

Non-Connected to

Wells, 15.0%

High Abandonment

Pressure, 2.7%

Communicating

Capillary Bound ,

19.8%

No DisplacementDrive Energy, 17.6%

Poor Sweep Efficiency,

13.3%

Produced and Trapped Oil Mechanisms as Percentage of OOIP

Deepwater Gulf of Mexico, Neogene Age Reservoirs

Total EURNon-Connected to Wells

High Abandonment Pressure

Communicating Capillary Bound

No Displacement Drive Energy

Poor Sweep Efficiency

see discussion on the calculation of

trapped oil volumes on next 2 slides


7/52

Trapped Oil Mechanisms Backgound

EUR (expected ultimate oil recovery) 31.6% Using ReservoirKB and MMS databases, determine OOIP, EUR, and average oil recovery

factor of 31.6% from 78 oil fields

Non-Connected to Wells 15%

Used a subset of 13 Neogene age fields

Assume significant faults are sealing, and blocks without a well penetration are consideredNon-Connected OOIP

The 13 fields contained 94 fault blocks of which 41 fault blocks were un-penetrated

Estimate OOIP in Non-Connected fault blocks by Area only, not net rock volume (NRV)

Result: 45% of fault blocks undrilled but represents only 15% of OOIP

High Abandonment Pressure 2.7%

Assume abandonment pressure can be lowered by 1600 psi

Estimate total compressibility, Ct = 20 E-6 psi-1

Calculate incremental production Np/N = Ct x Delta Pressure = 3.2%

Apply to Connected OOIP, thus 3.2% x 0.85 = 2.7%


8/52

Trapped Oil Mechanisms Backgound(continued)

Communicating Capillary Bound 19.8% Estimate average Swi = 20% and Sor = 20%

Capillary Bound = (1-Swi-Sor)/(1-Swi) = 25% of OOIP

Apply to Connected OOIP, thus 25% x 0.85 = 21.3%

Reduce by amount of Bound Oil expansion and production from Pi to Pabandonment usingtypical black oil with GOR=800 scf/stb, and Oil FVF change from 12500 5000 psi

[Boi = 1.305 and Bo at 5000 psi = 1.392, thus expansion = 6.7% Recovery of Connected and Bound Oil by expansion = 21.3% x 0.067 = 1.4%

Reduced connected capillary bound oil to 21.3% - 1.4% = 19.8%

No Displacement Drive Energy 17.6%

Produced plot of cumulate OOIP vs produced cumulative water/oil ratio for 49 mature oilfields to determine how much water displacement is occurring. Select cut-off of cumulativeproduced WOR < 0.1 to determine OOIP with no aquifer drive energy (see next slide)

Estimate 57% of OOIP has limited aquifer drive energy

Assume remaining 43% of remaining Connected and Moveable oil is left behind due topoor sweep efficiency

Calculate as (1 31.6% - 15% - 2.7% - 19.8%) * 0.57 = 17.6%

Poor Sweep Efficiency 13.3%

Calculate as (1 31.6% - 15% - 2.7% - 19.8%) * 0.43 = 13.3%


9/52

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0 1.1 1.2

Pe

rcentCumu

lativeRemain

ingOilIn-P

lace

Cumulative Water/Oil Ratio as of April 2008

Cumulative Original Oil In-Place vs Cumulative Water/Oil Ratio

from 49 Deepwater Gulf of Mexico Oil Fields

MinimalAquiferInflux

Natural Drive EnergyFrom Aquifer Influx


10/52

Revised IOR Process List

Water Injection

Conventional waterflooding

Raw seawater injection in subsea wells Dump flooding

Water-based EOR

Microbial EOR

ASP

Surfactant and contact angle modifiers

Gas Injection

Hydrocarbon gas injection Hydrocarbon gas dump flooding

Gas-based EOR

Air injection

CO2 injection

Nitrogen injection

Pumping and Artificial Lift

Subsea multi-phase pumping In-well ESP

In-well gas lift

Subsea processing

Well Technology

Low cost wells

Low cost intervention

Horizontal and Multi-lateral wells


11/52

IOR Processes - Evaluation Plan

Process

NumberIOR Category IOR Process Target Trapped Oil Mechanisms Low High

Field

Count

Target

OOIP

(MMSTB)

Low Case

(MMSTB)

High Case

(MMSTB)

Low Case

($/BBL)

High Case

($/BBL)

Technical

Readiness

Factor

Risk

Factor

Process

Ranking

1 Water Inje ction Conventional Water Inje ction Drive Ene rgy, Swee p Efficiency

2 Raw Seawater Injection Drive Energy, Sweep Efficiency

3 Aquifer Dump Flooding Injection Drive Energy, Sweep Efficiency

4 Water-Based EOR Microbial EOR Capillary Bound

5 Alkaline Surfactant Polymer (ASP) Capillary Bound; Sweep Efficiency

6 Chemical Augmented Waterflooding Capillary Bound

7 Gas Injection Hydrocarbon Gas Injection Drive Energy, Sweep Efficiency

8 Hydrocarbon Gas Dump Flooding Drive Energy, Sweep Efficiency

9 Gas-Based EOR Nitrogen Injection Drive Energy, Capillary Bound

10 CO2 Injection Capillary Bound

11 Air Injection Capillary Bound, Drive Energy

12 Pumping & Art if ic ial L if t Subsea Mult i-Phase Pumping High Abandonment Pressure

13 In-Well ESP Abandonment Pressure, Sweep Efficiency

14 In-Well Gas Lift Abandonment Pressure, Sweep Efficiency

15 Subsea Processing High Abandonment Pressure

16 Well Technology Low Cost Wells Non-Connected Volume

17 Low Cost Well Intervention Abandonment Pressure, Sweep Efficiency

18 Horizontal / Multi-Lateral Wells Non-Connected Volume, Sweep Efficiency

Technical IOR RF Indicative EconomicsTarget Potential BarrelsApplications


12/52

IOR Process AnalysisWater Injection


13/52

Waterflood evaluation workflow

Review from GoM experience

Determine incremental IOR

Estimate depletion recovery for fields with waterflood from startup

Use simulation to assist in the forecast of IOR for the new

waterfloods (post primary) Document issues and technical gaps for GoM waterflood

Review raw seawater and dump flooding experience to determine ascaled reduction off conventional waterflooding


14/52

GoM water injection experience

1. Petronius Field, J1 and J2 reservoirs2. Mars Field, N-O Sd (Yellow), M1/M1 Sd (Green), E Sd (Pink)

3. Horn Mountain, M Sand

4. Holstein, J2 and J3 reservoirs

5. Ram-Powell, N Sand (minimum injected)

6. Ursa Field, Yellow Sand

7. Princess Field (Ursa satellite), Yellow Sand

8. Morpeth Field (EW921), M-2/P Sand(SPE paper says project shut-down after poor early sweep results)

9. Amberjack Field, G sand10. Bullwinkle (was halted after early response)

11. Lena Field

12. Pompano, M83C-85 Sand (short injection history)


15/52

Overview of Petronius Field

First Production 2000

VK 786; Facility compliant tower

Middle Miocene, sheet sand

Water injection in 2 primary reservoirs, J1 and J2,commences 7 months after start of production

Normal pressure, slightly under-saturated, gas cap in J1zone, and modest rock compaction


16/52

Petronius Field, J2 Sand Performance

1000

10000

100000

Jul-00

Jul-01

Jul-02

Jul-03

Jul-04

Jul-05

Jul-06

Jul-07

Jul-08

Jul-09

OilRateandWaterInjection

Rate(BBL/day)

1%

10%

100%

WaterCut

Oil Rate Injection Rate Water Cut


17/52

Petronius performance summary

Mature waterflood and goodconfidence in prediction ofultimate recovery

Estimate depletion recoveryusing material balance

Assume Cr = 15 microsips dueto 0.5 psi/ft low initial pressuregradient

High incremental recoveries

for water injection No reported issues with wells,

completions, scaling, souring,or other production problems

ZoneOOIP

(MMSTB)

Waterflood

RF

Depletion

RF

(MBAL)

IOR

J1 109 57% 20% 37%

J2 80 54% 27% 27%


18/52

Overview of Mars Field


MC 807, Facility 24-slot TLP Upper Miocene and Pliocene reservoirs

Water injection commence 2004 in 3 reservoirs

N/O (Yellow) Sand

M1/M2 (Upper Green) Sand

E (Pink) Sand

Over-pressured, highly compacting, no aquifer influx, and

water injection installed after primary production

Meckel, etal2002 GCSSEPM Conf.

Reynolds2000 GCSSEPM Conf.


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1%

10%

100%

1000

10000

100000

Jan-96

Jan-97

Jan-98

Jan-99

Jan-00

Jan-01

Jan-02

Jan-03

Jan-04

Jan-05

Jan-06

Jan-07

Jan-08

Jan-09

Jan-10

WaterCut

O

ilRateandWaterInjectio

nRate(BBL/day)

Mars Field, N-O (Yellow) Sand Performance



20/52

Mars, N-O Sand

Weiland, et alSPE 115591

Production / ObservationN Producer

N / O Injector

OOIP = 573 MMSTB

5 producers (current)

1 injector

Depletion 4500 psiVoidage ~ 45 kbpd

Injection ~ 22 kbpd


21/52

Mars performance summary

New waterflood and not possible topredict performance RF

Primary depletion RF from establisheddecline analysis

Simulation sector model used to

estimate waterflood IOR (first matcheddepletion RF)

High potential incremental oil RF

Many challenges on injector integrity:

2 of 3 injectors with compromisedmechanical integrity

Sand control issues with fracture rateinjection; sand fill affecting verticalconformance

Tubing leak related to O2 corrosion

Out of zone injection observed

ZoneOOIP

(MMSTB)

Waterflood

RF

(Eclipse)

Primary

RF

(decline)

IOR

N/O 573 56% 37% 19%

M1/M2 341 56% 31% 25%

E 225 56% 35% 21%


22/52

Overview of Horn Mt. Field


MC 127; Facility Spar Middle Miocene

Primary development and injection in M Sand

Normal pressure (0.52 psi/ft), moderately under-saturated,and modest rock compaction

Sand-filled channels and associated levees and overbanks

Milkov, et al

AAPG Bulletin

MC127#1ST1


23/52

Horn Mt. Field, M Sand Performance

1000

10000

100000

Nov-02

Nov-03

Nov-04

Nov-05

Nov-06

Nov-07

Nov-08

OilR

ateandWaterInjection

Rate(BBL/day)

1%

10%

100%

WaterCut



24/52

Horn Mountain performance summary

Mature waterflood with good confidence in

performance prediction 4 producers in west with good response to

water injection

3 producers without good support (and nooffset injector) in east

Infer channel-levee environment requires

2:1 prod/inj ratio

ZoneOOIP

(MMSTB)

Waterflood

RF

Depletion

RF

(MBAL)

IOR

M 280 40% 20% 20%

Milkov, et alAAPG Bulletin


25/52

0%

10%

20%

30%

40%

50%

60%

0.0 0.1 0.2 0.3 0.4 0.5 0.6

Injected Water, PV

RecoveryFactor(%)

Mars N-O sandPetronius J1 sand

Petronius J2 sandHorn Mt. M sandRam-Powell N sandMars E SandMars M1-M2 SandHolstain J2 SandHolstain J3 Sand

Petronius, J1

Petronius, J2

Holstein J3

Holstein, J2

Horn Mt M

Mars, N/O,

M1/M2, E

Oil RF versus pore volume water injected


26/52

Simulation forecasting tool

Eclipse simulation sector model used to forecast incremental recovery

Grid blocks: I=26, J=26, K=58 Several facies and property models available

Upper Miocene, high NTG, high permeability, highly compacting rock (Mars Field example)

Paleogene stratigraphy based on Jack Field discovery well (digitized)

Simple screening tool using typical DW GoM properties


27/52

Simulation forecast of DW GoM secondarywaterflood after primary production in highlycompacting reservoir

RF= 56%

RF= 51%

RF= 39%


28/52

Summary IOR for DW GoM waterflooding

Notes:

1. Based on decline analysis prior to start of injection.

2. No performance indication of waterflood RF; use simulation

model to determine waterflood RF as function of VIRR.

Field Reservoir OOIP

Cum Oil

@Sep, 2009

(mmstb)

Recovery

Factor@

Sep,2009

Estimated

depletion

RF by

MBAL

Performance

Based Oil

EUR (mmstb)

Performance

Based RF

Waterflood

IOR

N 573 170 30% 37%1

321 56%2

19%

M1/M2 341 86 25% 31%1

191 56%2

25%

E 225 50 22% 35%1

126 56%2

21%

J1 109 59 54% 20% 62 57% 37%

J2 80 42 52% 27% 43 54% 27%

Horn Mt. M 280 81 29% 20% 112 40% 20%

J2 138 23 17% 15% 40.5 29% 14%

J3 84 11 14% 15% 16 19% 4%

Petronius

Holstein

Mars


29/52

Observations Water Injection

IOR potential for waterflooding is 4 20% of OOIP The only deepwater GoM successes are with dry tree installations

Also, successes are primarily in reservoirs not highly over-pressured Exception is Lobster Field, EW 873 (taken off deepwater list since water depth is

775 ft) where initial pressure gradient was 0.68 psi/ft dry tree facility withinjection from near the start of production

Issues to overcome for late life injection in over-pressured, highlycompacting reservoirs: Pressure differentials between stratigraphic units

Completion failures, particularly sand control

Casing integrity and out of zone communication

Successful operation of subsea injector in Morpeth for 5 months Downhole filtration system to stop solids loading from corrosion products

Sustained good injectivity index ~ 25 bwpd/psi for 135 days

Injection stopped due to reservoir reasons (rapid water BT in offset well)


30/52

Raw Seawater Injection


31/52

Overview of raw seawater injection

Applications: Subsea developments with distance from remote host

Developments with facilities space and weight limitations

Extended reach drilling issues from existing platform

Smaller fields/reserves with marginal economics

Potential application for DW GoM: K2, Genesis, Blind Faith, Medusa, Brutus, Front Runner, Llano, Europa, etc.

State of Play for industry use of raw seawater injection: Installations (or near implementation) at Tyrihans (Statoil, Norway), Columba

(CNR, UKCS), Barton (Shell, Malaysia), and Albacora (Petrobras, Brazil)

Leveraging North Sea research and Joint Industry Projects such as RawwaterEngineering and PWRI

Ongoing development of modeling software for nitrate inhibition, scaling andsouring predictions


32/52

Tyrihans Field, Norway

Installation in 2009 Two accumulations of gas condensate and oil rims connected by

common aquifer

Not expected to produce injected raw water

Subsea development with distance of 22 miles from host platform

Projected benefits: Original Liquid In-Place = 435 MMSTB, IOR for water injection = 4.4% of in-place

Gynning, et al, OTC 20078 (2009)


33/52

Columba Field, UK northern North Sea

Wet test in 2006, installation dateuncertain

Columba field is extension off southend of Ninian field

Primary production from Phases I andII commenced in 1998

Space and weight limitations on NinianSouth platform, 7 km distance

Injection to support 4 producers with80 MMSTB connected OOIP

Leveraging on Joint Industry Project,

UK/Norway, Rawwater, 1993 1998 Economics: Considered in a

Greenfield context, the conventionalpipeline based subsea system was themore economic solution out to a stepout distance of 8 km

Rogerson and Laing, SPE 109090 (2007)


34/52

Barton Field, Malaysia

Reported plan in 2004, installation dateuncertain

Small field with marginal economics;requires new water injection platform orlow cost system (raw seawater)

Reservoir pressure drop from 1058 psi to550 psi over 20 years

IOR potential 6% of OOIP

Leveraging Shell participation in NorthSea initiatives

CAPSIS

PWRI

Engineered Issues List: Filtration or injection of suspended solids

O2 corrosion (GRE and high grade CRA) Reservoir souring (nitrate and biocide additives)

Scaling (CaCO3 and BaSO4)

Combination microbial EOR effect

Use naturally occurring bacteria whichfeed on carbon and the nutrients providedby Nitrate, O2 and Phosphates

Flatval, et al, SPE 88568 (2004)


35/52

Dump Flood Water Injection


36/52


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SummaryLow cost water injection options

Raw seawater injection and dump aquifer flooding are being used inother offshore basins for low cost water injection options

Applications for DW GoM are subsea tie-backs, marginal sizereservoirs, and facilities with space and weight limitations

IOR RF = 4% for low case (same as for conventional waterflooding) IOR RF = 14% for high case Downgrade convention high case IOR by 30% due to reduced ability for reservoir

management

Projected cost savings from Rawwater JIP (1998) is 40 60% overcost of conventional waterflooding This figure may be out of date and not applicable to deepwater GoM


38/52

Workflow to determine the number ofapplications for an IOR process


39/52

IOR Process Neogene Evaluation

Process

NumberIOR Category IOR Process Target Trapped Oil Mechanisms Low High

Field

Count

TargetOOIP

(MMSTB)

Low Case

(MMSTB)

High Case

(MMSTB)

Low Case

($/BBL)

High Case

($/BBL)

1 Water Injection Conventional Water Injection Drive Energy, Sweep Efficiency 4.0% 20.0% 26 16,567 663 3,313

2 Raw Seawater Injection Drive Energy, Sweep Efficiency 4.0% 14.0% 27 7,337 293 1,027

3 Aquifer Dump Flooding Injection Drive Energy, Sweep Efficiency 4.0% 14.0% 27 7,337 293 1,027

4 Water-Based EOR Microbial EOR Capillary Bound

5 Alkaline Surfactant Polymer (ASP) Capillary Bound; Sweep Efficiency

6 Chemical Augmented Waterflooding Capillary Bound

7 Gas Injection Hydrocarbon Gas Injection Drive Energy, Sweep Efficiency

8 Hydrocarbon Gas Dump Flooding Drive Energy, Sweep Efficiency

9 Gas-Based EOR Nitrogen Injection Drive Energy, Capillary Bound

10 CO2 Injection Capillary Bound

11 Air Injection Capillary Bound, Drive Energy

12 Pumping & Art if icial Li ft Subsea Mult i-Phase Pumping High Abandonment Pressure

13 In-Well ESP Abandonment Pressure, Sweep Efficiency

14 In-Well Gas Lift Abandonment Pressure, Sweep Efficiency

15 Subsea Processing High Abandonment Pressure

16 Well Technology Low Cost Wells Non-Connected Volume

17 Low Cost Well Intervention Abandonment Pressure, Sweep Efficiency

18 Horizontal / Multi-Lateral Wells Non-Connected Volume, Sweep Efficiency

Notes:

1. Conventional water injection IOR range from detailed review of Gulf of Mexico deepwater projects; Use low side and 70% of high side conventional IOR for Raw Seawater and Dump Waterflooding

Technical IOR RF Indicative EconomicsTarget Potential BarrelsApplications


40/52

Number of applications water injectionAssumptions

Injection in significant reservoirs with OOIP > 10 MMSTB

If dry tree facility, then conventional water injection; can also consider rawseawater and dump flooding

If forecast oil RF > 45%, no injection required

If subsea development and remote distance from host, assume raw seawater

injection and dump flooding If subsea and total field OOIP < 50 MMSTB, no injection

Other Assumptions:

Count of applications is the number of fields

Sum OOIP from significant reservoirs where field is applicable

Target total OOIP is scaled up by ratio 31BSTB / Database OOIP

Scaling factor of OOIP = 31 / 25.3 = 1.226

Note: scaling for discovered Neogene under appraisal / development

N b f li ti t i j ti


41/52

Number of applications water injectionSample from database


42/52

IOR Process Analysis

Gas Injection


43/52

IOR for hydrocarbon gas injectionEvaluation method options

Analytical models: e.g. SelectEOR, which predicts oil recoveryfor waterflooding, chemical and gas injection processes based onanalytical calculations

Correlative methods: similar to Haskin & Alstons* method for

estimating CO2 huff n puff recovery based on 28 field tests; Reservoir simulation

Values based on analog fields in the North Slope and North Sea

* Haskin, H.K., and Alston, R.B., An Evaluation of CO2 Huff n Puff Tests in Texas, Journal of Petroleum

Technology, February 1989.


44/52

Current status and plan

Use SelectEOR (LSU) to evaluate a sample set of DW GoMreservoirs for hydrocarbon gas injection (e.g. K2 Field)

Evaluate Eclipse sector model for scoping IOR values

Summarize IOR values report for North Sea and North Slope

Summarize technical issues observed in fields where gas injectionwas implemented


45/52

IOR Process Analysis

Pumping and Artificial Lift

O i f i d


46/52

Overview of pumping andartificial lift methods

Applications: Lower abandonment pressure in depletion drive reservoirs

Produce wells to high water cuts

Longer subsea oil development tie-backs

Potential application for DW GoM:

Subsea developments where abandonment maximum water cuts tend to be lessthan 60%

Low GOR fluids

Recommended analysis plan: Assume 3% IOR as determined during screening phase

Summarize a capture of information on current state of technology and

application

Riser based gas lift (e.g. Girassol)

Riser based centrifugal pump (e.g. Perdido Hub)

Petrobras gas lift of subsea wet trees

Subsea ESP (e.g. Albacora Leste single well, and Cascade manifold)


47/52

Technology Transfer


48/52

Pennwell DOT presentationby Art Schroeder, 2nd February


49/52

OTC #20678 for presentation atMay 2010 conference by Joe Lach


50/52

SPE #132633 poster at May 2010Western Regional meeting by Xin Li

Title: Investigation of Trapped Oil Mechanisms and Opportunitiesfor Improved Oil Recovery in Deepwater Gulf of Mexico

Abstract: Deepwater Gulf of Mexico oil fields (DW GoM) typically get modest Ultimate Recovery Factors in the10% - 35% range, because reservoirs tend to be small, deep, and complex. The Remaining Oil target for Improved OilRecovery (IOR) is tempting large, with about 40 Billion Bbl estimated to be left in discovered fields at abandonment.

Procedures on by-passed oil mechanisms analysis are based on analysis of field data compiled by Minerals ManagementService, on data extracted from focused literature reviews, and on original work to analysis by-passed oil mechanisms anddescribe the remaining oil distribution in turbidite reservoirs of DW GoM.

This paper describes a study on oil trapped mechanism, by-passed oil categories and their distributions. It is key part ofstudy directed at recommending a select group of IOR processes for multi-million dollar Research & Development fundingby Research Partnership to Secure Energy for America (RPSEA).

The DW GoM oil fields have been catalogued and characterized by geological setting and reservoir engineering. (1) By-

passed oil depends on structure settings and depositional system. The trapped oil mechanism was reviewed in the contextof eight defined geologic classification types for structural setting and depositional environment. (2) Detailed examinationof reservoir performance and simulation studies has been conducted for a number of GoM fields and reservoirs. In thisstudy, case study with actual field data for Neogene age Tertiary reservoirs is included, and followed by conclusions.

Authors established static and dynamic model referring MMS database to quantify by-passed oil. This work defines thesignificance of bypassing mechanisms so that appropriate IOR methods can be selected in DW GoM.


51/52

Forward Plan


52/52

Forward work plan

Complete assessment of Neogene IOR potential and number ofapplications for all processes by March 15th

Commence economic assessment ($/IOR BBL) of Neogene IOR, byprocess, March 15th

Attend Det Norske seminar on Technical Readiness 26-Feb

Revise IOR evaluation plan for Paleogene reservoirs and beginassessment start 1st April

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07121-1701_KR Presentations_Working Committee_16 Feb 2010

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