Chapter 5 (Reservoir Description)Lb13wS2a

8/9/2019 Chapter 5 (Reservoir Description)Lb13wS2a

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Chapter 5

Reservoir Description

Presenter: Leigh Brooks

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Reservoir descriptionWhat do we want to do?

Most simply:

1.Estimate the amount of hydrocarbons in place in your fieldie Original Oil in Place (OOIP) and/or

Original Gas in Place (OGIP)

Simply:OOIP = trap Volume x Net/Gross (N/G) x Porosity () x OilSaturation (S o) x Oil shrinkage (1/B o)

OGIP = trap Volume x Net/Gross (N/G) x Porosity () x GasSaturation (S g) x Gas Expansion Factor


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2. Estimate how much can be economically recovered.

This (recovery factor) is dependent on: how the oil and gas is distributed within the field (determined bystructure, sedimentary facies distribution ie distribution of particularrock types deposited in certain depositional environments, fluidcontacts, porosity () , permeability (k))

the quality of the reservoir ie how fast it can produce (permeability)

the reservoir drive mechanism ie pressure support for producing

(flowing or pumping) the hydrocarbon (determined by the extent andquality - porosity, permeability - of the connected aquifer (waterbearing rock))

Number of wells and Capital costs of the development

Reservoir descriptionWhat do we want to do?


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Reservoir description

Both these objectives require a model of the reservoir

OOIP is the first step and may be achieved with astatic model

The second step (estimating recovery and productionperformance) requires a dynamic model constructed byengineers to simulate the flow of fluids through thereservoir over time. Multiple scenarios are generally

modelled to understand the range of outcomes


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Example of an attribute display from a reservoirsimulation model


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Trap Volume generally determined by geological and geophysical

mapping but may be determined by pressure data obtained duringproduction Net / Gross is the ratio of net effective reservoir (that which will

contribute to production) to gross interval. This is generallydetermined by permeability and porosity and is a function of theenvironment of deposition. It will vary laterally and vertically

Porosity () is the pore vol/gross vol of reservoir lithology Oil Saturation (S o) is the fraction of the pore space occupied by

oil and = (1- Water Saturation (S w)) This is determined bypermeability and capillary pressure and hydrocarbon column anddensity

Oil shrinkage (1/ Formation Volume Factor or B o) Oilformation volume factor (Bo ) can be defined as ratio of Oil Volumeat reservoir condition to Volume at the surface condition (at 60F and14.7psi). As pressure decreases when the oil comes to the surface,gas bubbles out, reducing the volume of the oil)

OOIP = trap Volume x Net/Gross (N/G) x Porosity () x Oil Saturation (S o) x Oil shrinkage (1/B o


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OOIP in millions stock tank barrels (STOIP)

=trap Volume (10 6 cu m) x Net/Gross (N/G) x Porosity () x Oil

Saturation (S o) x Oil shrinkage (1/B o) x 6.2898

OGIP in Billions cu ft (Bcf)

= trap Volume (106

cu m) x Net/Gross (N/G) x Porosity () xGas Saturation (S g) x Gas Expansion Factor x 35.3 x1/1000

A reasonably good approximation to Exp Factor can be simplycalculated from The Ideal Gas Law PV=nRTand a good estimate can be made by incorporating the z factorP 1V1=z 1nRT 1 and P 2V2=z 2nRT 2 and calculate V 1/V2. T is degKelvin (ie 273 + deg C)


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Reservoir descriptionTo achieve this requires a co-ordinated FormationEvaluation process involving many disciplines

A perspective of scale

ORDER OFMAGNITUDE (m) TECHNIQUE PURPOSE

106 Satellite imagery Gross structure

105 Basin geologic studies '' ''

104 Seismic, gravity, magnetics '' ''103 Borehole gravimeter Local structure102 Drillstem tests, seismic Productivity and reserves101 Wireline formation tests '' ''10 0 Full-diameter cores Local porosity, permeability

and lithology10 1 Side wall cores, most well logs,

measurement while drilling (MWD)'' ''

10 2 Micro-focused logs, core plug analysis '' ''

10 3 Cutting analysis (mud logging) Local hydrocarbon content10 4 Core analysis Rock properties10 5 X-ray mineralogy Rock and clay typing10 6 Scanning electron microscope (SEM) Micro pore structure


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Formation Evaluation continues but changes throughfield life


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Log measurements , when properly calibrated by core and test information, can give the majority of the parameters required.

Most of this information is gathered in open hole, either Logging WhileDrilling (LWD) or by wireline . Some information can be gatheredthrough casing

Specifically, logs can provide either a direct measurement or a goodindication of: porosity, both primary and secondary (fractures and vugs) permeability water and hydrocarbon saturation and hydrocarbon movability hydrocarbon type (oil, gas, or condensate) lithology formation (bed) dip and strike sedimentary environment (facies) travel times of elastic waves in a formation

Formation Evaluation


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Limestones are the most important reservoir lithology by volume ofconventional hydrocarbon stored, by virtue of the huge reserves in theMiddle East and Mexico.-Carbonate/limestone (CaCO 3) deposition requires a relative lack ofclastic sedimentation (sands, silts, muds) and high organic productivity(being a product of biogenic activity), which increases towards theequator as solar illumination increases- Salinity and temperature are the 2 main controls on carbonatedeposition- porosity and permeability distribution is more complex than in clastics,due to more common dissolution and cementation

Clastic sandstones are also very important reservoirs and are themost common.

- We will focus mainly on these as, although the principles are the same,the factors governing reservoir distribution and performance aregenerally easier to understand and are better documented in clastics.

Main reservoir types are sandstones and limestones


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Porosity can be measured from core and from wireline and Logging Whiledrilling (LWD) logs. Indirect measurements from logs must be calibrated tomeasurements from actual rock ie core

We will discuss1) physical properties of rocks that affect (and k), mainly for clastics2) the methods of collecting physical core3) methods of measuring from core and logs


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Thin section of rock under microscope showing porosity inblue and Mercury Injection Capillary Pressure data showingpore throat size distribution


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1) Physical properties of rocks that affect (and k)


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Because carbonates are moresoluble (in slightly acidic waters)than clastics, porosity is morecommonly secondary, governedby dissolution and cementationprocesses


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Microscopic section of an oil-bearing rock

Di i


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Diagenesis

Primary porosity decreases withdepth due to diagenesis thecompaction under increased burialpressure, and cementation of thepores with carbonate, silica, claysand other cements at increasingtemperature and pressure

This trend may be reversed locally bythe creation of secondary porosity by- dissolution of unstable grains ofminerals such as feldspar- dissolution of more solublecomponents in carbonates

- dolomitisation of limestone, whichwill lead to an increase in porosity(vol of dolomite is less because it ismore dense)

Di i


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Diagenesis

Diagenesis depends on1)rock composition and textures ie mineralogy, grainsize, grain shape andpacking (compaction processes)2)composition and nature of the pore fluids ie ionic concentrations, rate andvolume of the fluid moving through the pores, pressure and temperature(cementation processes)

Compaction reduces porosity by crushing brittle rock grains like shells and

feldspars, grain slippage and rotation with their effect on the grain packing,compression and squeezing of ductile grains like mica into pore spaces, andpressure solution where mineral grains are dissolved under pressure andreprecipitate in adjacent pores.

Cementation occurs if the pore fluid is supersaturated in the elements comprising

the precipitate. Cements require clean nucleation sites if the sand is dirty andcontains some clay, cementation may be inhibited.

Secondary porosity can be created by the leaching of unstable compounds


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Texture of clastic rocks sorting and angularity affect both


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Texture of clastic rocks sorting and angularity affect bothporosity and permeability


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Poor porosity and permeability. whenconsolidated

Eff t f ki f i it d bilit


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Effect of packing of grains on porosity and permeability

Range of permeability

Grain shape and sizeeffects on porosity

High Permeability

Lower Permeability(for same porosity)

Porosity47.6%

47.6%

25.9%


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Grainsize, grain sorting and shape are highly influenced by thedepositional energy and environment in which they were deposited

and the geology of the sediment provenance area.

Sand bodies are often not sheet-like. Orientation and distribution ofsand bodies depends on the depositional environment as is thequality of the sand.

These will be discussed further in a later lecture.


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Effective, Non-effective and Total porosity

Largely noneffective

2. methods of collecting physical core coring


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Objectives: definition of porosity, permeabili ty, directional

permeability, relative perm, wettability, abil ity to predict f luidsaturations, irreducible water saturation, lithology, sedimentary facies,information to calibrate logs including electrical properties of therocks

Conventional full diameter core - cut and recovered during the drillingprocess .- Variable diameter but generally ~4.5 diameter.- expensive, so comprehensive planning to maximise recovery- non rotating inner core barrel / liner of Al, fibreglass or PVC plastic to maximiserecovery and minimise damage- liners preserve even unconsolidated core for high quality analyses in the laboratory- can cut > 50m continuous core- new bit techology allows coring without pulling drill bit out of hole and running inwith core bit and barrel. Plug in bit is retrieved by wireline and liners run by wireline- a gamma ray log of the core is recorded through the liner

Rotary sidewall core cut and recovered on wireline after dri lling the sectionof hole- mechanical rotary coring tool run on wireline- can take up to 60 small coreplugs in one run

- rock fabric remains intact so plugs are suitable for permeability and

2. methods of collecting physical core coring


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Rig floor sampling- in the old days we dont usually do this now.Cores are preserved in liners and sleeves for transport to the laboratories to minimise the chance ofdamage to the core

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Usually half of each core, sliced lengthwise (slabbed), is preserved intact as thearchive section, and the other half is extensively sampled and described.

Alternatively the core is slabbed, into 1/3 (for the geologist) and 2/3 (for thepetroleum engineer who has to take plugs for testing

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Rotary sidewall coring tool run into the wellbore on wireline


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Rotary sidewall coring tool run into the wellbore on wireline cuts 1 or 1.5 diameter cores

I dditi t f l l di t d t id ll


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In addition to ful l diameter and rotary sidewall cores,percussion sidewall cores can also be collected

Percussion s idewall coring .- wireline core gun that uses a percussion charge to shoot a hollow

cylinder into the wellbore. This core barrel captures formation materialand holds the material in place during retrieval to surface.

- a maximum of 74 samples can be taken per run at specified depths- rock fabric is damaged so not suitable for porosity and permeability butsamples suitable for hydrocarbon show identification, lithology, mineralogy,age dating


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Sidewallcoring

bulletafterleavingthe gun

3. Measurement


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3. MeasurementLab measurement of porosity usually by He injectionPore volume measured using a porosimeter and Boyles LawP 1V1 = P 2V2and = Pore vol/bulk volP 1 = 0 psig and V 1= vol reference chamberValve between sample chamber and ref chamber opened and final P 2 pressuremeasured. V 2 = vol sample chamber V g (which is vol of grains)Vb measured by displacement or linear measurement

Lab measurement of porosity at ambient conditions needs to be


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Lab measurement of porosity at ambient conditions needs to becorrected to represent (slightly lower) porosity at the higherpressures present at actual formation depth

Illustration of the decrease in porosity of some samples with


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Illustration of the decrease in porosity of some samples withincreasing OB pressure


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Thin section showing porosity in blue and Mercury InjectionC ill P d h i h i di ib i


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Capillary Pressure data showing pore throat size distribution,which determines permeability


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But firstly what are logs and how are they acquired?


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But firstly what are logs and how are they acquired?

Logs are made by:

Moving a tool string with various tools attached at acertain logging speed, and recording data at certainintervals called sampling rate

The log is the recording of each of these datasamples at a recorded depth

We usually record logs by lowering the loggingtools to the lowest point in the well and then movingthe tools upward while acquiring data .


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Different tools at different depths and different volumes of investigation (yellow shapes)


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Vertical resolutiondependent on loggingspeed

D t A i iti D th M t


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Data Acquisition Depth Measurement

The first well logs were recorded in 1927


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The first well logs were recorded in 1927

Modern Logging Truck


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Modern Logging Truck

Inside a wireline logging shack


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Standard Logging String


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Standard Logging String- allows an evaluation of reservoirand fluid in a single run

Formation Gamma Ray

Neutron Porosity

Density (Porosity)

Caliper (hole size)

Pad Resistivity (good vertical resolution)

Resistivity (good depth of investigation)

Spontaneous Potential

Mud Resistivity

Conveyance methods


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Conveyance methods Wireline Logging Logging through pipe Logging on Drill Pipe (Tough

Logging Conditions) Logging Using Tractor

Logging-While-Drilling

Wireline

Tractor

TLC


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Log readings are notfollowing the same pathin vertical and horizontalwells

Interpretation of logs


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Interpret lithology Identify objective reservoir seal pairs

Use to evaluate potential source intervals Correlate logs to interpret sequence stratigraphy to give sedimentary faciesof important intervals Interpret rock properties such as porosity and permeability, and fluidsaturations Interpret fluid systems, OWC, GWC, GOC etc

Tie to seismic data Use to model seismic response for possible rock properties and fluid types tounderstand seismic data

Remember the best interpretation is achieved by calibrating to core


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Cross-over of density& neutron log traces in good rock indicates gas

slower high


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Density log ( b) good estimate of T in absence of gas


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= ( matrix - b )/ (matrix - fluid )

Neutron measures H so sees H in water in pores and bound in shales


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Sonic


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Nuclear Magnetic Resonance- measures phi and k


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Nuclear Magnetic Resonance- measures phi and k. Goodindicator of mobile fluid ie rock that can produce fluid vs that


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Small pores irreducible

water ie willnot flow

Large pores mobile fluid

ie producible

which is tight and cannot

Other logs commonly used forcomplete reservoir evaluation:


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Mudlog/lithologic log (lith, fluid)Gamma ray (lithology)Resistivity (S w)Borehole caliper (k if mudcake)Spontaneous Potential (lith,k)Image logs eg microresistivity tool FMI(Formation Micro-Imager) (lith, dips,

fractures,fault)Photoelectric absorption (lith)Pressure and formation fluid sampling tools(fluid, k)Vertical Seismic Profiler/seismic checkshot(seismic welltie )

MWD drilling parametersPermeability probe in lab (k)


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(Volume of clay bound water)


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logs

Important summary

( y )


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Egs of other logs Gamma Ray (GR) and Resistivity (RES) andcomputed reservoir properties in right hand tracks


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Depositional facies


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Walthers Law of FaciesFacies that succeed eachother vertically without atime break wereoriginally depositedadjacent to each other

Facies

Facies association or modelseries of facies everywhere found togetherrepresent deposition of sediment in various parts of a singledepositional environment

The observable attributes of a sedimentary rock body that reflect the depositionalprocesses or environments that formed it.

Depositional facies interpreted from logs such as these recorded over fluvio-deltaic sands help predict reservoir distribution and quality


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Grainsizeincreasing

A Typical verticalShorefaceS

Beach-Foreshore

R E P O S E

D I N G

Grainsize increasingFacies


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Sequence- formed as the beach

progrades (moveslaterally) into the basindue to continuedsediment supply andyounger beachsediments are

deposited on top ofolder shoreface andoffshore sediments

Mid to Upper Shoreface: Convex-up Hummocks rarely preserved (loosely

termed swaly)

Lower Shoreface: HCSHummocky Cross-Stratification

Upper Offshore:Turbidites

Lower OffshoreMuds, shales

1 S T

A N G L E

_ O F _ R

C R O S S B E D D

Eg of different sedimentary facies that are deposited at the same time indifferent locations ie they are equivalent. The change in facies may occurwithin the field and they will have different /k relationships


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GRayGRay

GRay

N SDatumed Cross Section through Pohokura Field

TVDMD

MDMD

MD

Datum: KA-00


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Lower shorefaceUpper shoreface

Lagoon/coastal plain

The geometry of sediment distribution (depositional facies patterns andpreserved sediment) will vary with the balance between sediment supply andsea level


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Reservoir vs nonreservoir/waste


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zone vs seal

-waste zones, as the termimplies, are where lowpermeability non effectivereservoir are present in thetrap.

-They are important torecognise as they reduceeffective reservoir volume


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Different sedimentary facies havedifferent /k relationshipsThese must be factored in to an

High energyfluvio-deltaic

sands


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effective reservoir model

k

Low energymarine sands

Clearly porosity and permeability are fundamental tounderstanding the resource


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- What affects them and how do we measure them?

2. Permeability (k): is a measure of how easily a fluidflows through the rock. Unit is Darcy, although a morecommonly used unit is the milliDarcy (mD), which is 1D/1000.It is a function of the size and shape of the pore channels andtheir distribution.

Absolute k : permeability when only one fluid is present in the rock (measuredby core analysis)

Effective k : permeability of each phase when more than one fluid is present(measured by well tests)

Relative k (k r ) : is the ratio of effective to absolute k for each phase present. Asthere are always more than one phase present in the reservoir, formationflow is governed by k r (measured by core analysis)


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Permeability can be measured from core and estimated from wirelineFormation Testers and Well Tests. It can also be calculated from wireline andLWD logs. Indirect measurements from logs must be calibrated tomeasurements from actual rock ie core

We will discuss1.physical properties of rocks that affect k, mainly for clastics2.methods of measuring k from core and estimating from logs and tests


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ORDER OFMAGNITUDE (m) TECHNIQUE PURPOSE

10 2 Drillstem tests Productivity andreserves, k

10 1 Wireline formation tests

10 0 Full-diameter cores Local porosity,

permeabilityand lithology

10 1 Side wall cores, most welllogs, Measurement WhileDrilling (MWD)

10 2 Micro-focused logs, coreplug analysis

The most essential section of the table for us

Productivity andreserves, k

Local porosity,permeabilityand lithology

Local porosity,permeabilityand lithology

Texture of clastic rocks sorting and angularityaffect both porosi ty and permeabili ty


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Texture of clastic rocks grainsize affects k while sortingand angularity affect both and k


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Wireline Formation Testers record formation pressures andtake formation samples, including PVT samples. Permeability can be estimatedfrom the mobility using drawdown and buildup pressures

Downhole fluid analyser can be used to monitor phase of fluid


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y p

entering the tool


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Principles of Drillstem Testing: (a) Running in Hole (b) Setting Packer(c) Opening Flow Valve (d) Fluids to surface

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Permeability can be estimated from Well Test data.

The depth of investigation is much larger than either core, logs


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The depth of investigation is much larger than either core, logsor wireline testers and therefore is more representative offormation permeability.

Depending on the length of the test (and the amount of fluidwithdrawn from the formation) barriers within and boundaries ofthe reservoir can sometimes be seen.

Permeability, reservoir pressure and skin can be calculatedfrom all the data recorded during a test (pressure drawdown,production rates, pressure buildup vs time etc), using

sophisticated software such as Saphir by Kappa and Harmonyby Fekete


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Log analysis( t h i )


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(petrophysics)

Log analysis of k (using CoatesFree Fluid equation) and log

computed calibrated to coreanalysis data (red circles)


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Role of Initial Fluid Saturation in Modeling There is a general relationship between the amount of interstitial water and porosity, permeability

and grain size in the reservoir. As a general rule in formation evaluation, as the percentage ofreservoir water increases, the permeability, porosity and grain size decreases.


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The amount of recoverable hydrocarbons is directly based on the amount of water in the porespaces. Therefore water volumes are a necessary calculation before any hydrocarbon productioncalculation takes place.

Initial fluid saturation distribution of reservoir fluid phases is required for: Static modeling through definition of initial hydrocarbon in-place; Dynamic modeling, which aims to predict hydrocarbon production and recovery

March 6, 2012 PTRL3001 - N. Beliakova 95

Log analysisCalculation of Water Saturation S w (S w + S o =1 and so Oil and Gas

Saturation = 1-Sw) is an essential part of defining OOIP and OGIP


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The basic relationship used in fluid saturation estimations from logs is the

empirical Archies Law, although many variations and refinements havebeen developed.

Archies Law: S w = n Rw/R t. m

Rw is resistivity of formation water, from sample or calculated from logsR

tis true formation resistivity measured from deep investigation resistivity tool

m is the cementation exponent and is derived from core analysis(commonly ~ 2). Related to pore geometry

n is the saturation exponent and is derived from core analysis (commonly ~2). Related to wettability

The Law enables S w to be calculated from resistivity measured from logs.S w deceases ie S o increases with increasing formation resistivity at any

given/constant

The Law enables S w to be calculated from resistivity measured from logs.It assumes that electrical conduction in rocks results from the transport of


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pions in the pore filling brine. How easily these ions traverse a pore system

determines the rocks resistivity. In rocks with well connected open poresfilled with brine, ion flow occurs easily and the resistivity is low. Rocks withsinuous constricted pore paths, however, restrict ion flow and have highresistivityIn either case, ion flow paths become tortuous and resistivity increasescorrespondingly when some of the brine is replaced by non-conducting hydrocarbon.

Water saturation and hence oil or gas saturation can be estimated fromlogs provided they have been calibrated with core data.

Values from log analysis can be further calibrated against capillarypressure data

Remember the Traps lecture:

Seals are any rocks capable of holding a hydrocarbon column. They cando so because they have low permeability and very small pore throats.


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do so because they have low permeability and very small pore throats.

The quality of a seal is determined by the minimum pressure (due tobuoyancy of the hydrocarbon) required to displace connate water (normalwetting phase) from the largest pores or fractures in the seal, allowingleakage.

Capillary pressure , which determines seal capacity (and reservoir

quality), increases as the throat radius of the largest connected poresdecreases, as the wettability decreases and as the hydrocarbon- waterinterfacial tension increases.

Good sealPoor seal


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What is it? Capillary Pressure Definition

When t o immiscible fl ids (s ch as oil and ater) coe ist at eq ilibri m in a capillar t be


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When two immiscible fluids (such as oil and water) coexist at equilibrium in a capillary tube,there is a difference in pressure across their interface. This "Capillary Pressure" is caused by

the preferential wetting of the capillary walls by one of the fluids and gives rise to the familiarcurved meniscus.

Pc = Pnw - Pw

Pc = Capillary pressurePnw = Pressure of the non-wetting phasePw = Pressure of the wetting phase


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Quartz Sst, fri, f-m grain, part calc cmtd. Corephi=20%; K ir=~1D


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phi=20%; K air =~1DLoose qtz sand in ctngs, m-crs, (rnd)-rnd,

Oil zone (highresistivity)withsharp OWC ie vthin transition zonedue to high k

resistivity inwater zone

What is it? Capillary Pressure Definition

When two immiscible fluids (such as oil and water) coexist at equilibrium in a capillary tube,


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When two immiscible fluids (such as oil and water) coexist at equilibrium in a capillary tube,there is a difference in pressure across their interface. This "Capillary Pressure" is caused by

the preferential wetting of the capillary walls by one of the fluids and gives rise to the familiarcurved meniscus.

Pc = Pnw - Pw

Pc = Capillary pressurePnw = Pressure of the non-wetting phasePw = Pressure of the wetting phase

Capillary pressure characterist ics of reservoir rocks affectthe flow and distribution of fluids within the reservoir . It is one

of the most important measurements that can be made because it relatesreservoir rock and reservoir fluid properties. The magnitude of capillary


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pressure reported in laboratory tests relates to the height above the free waterlevel in the reservoir.

The relationship between capillary pressure and water saturationis dependant upon grain size, grain shape, packing, sorting and

cementation (environment of deposition and diagenesis). These all affect the

pore throat diameter distribution, often referred to as the pore sizedistribution (PSD) within the rock. The relationship is also

dependant upon the interfacial tension between the twoimmiscible phases present, the contact angle between the

wetting phase and the rock surface and the densitydifference between the fluids .

Capillary Pressure (P c)


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Well

Gas

Oil

Water

D

e p

t h

Pressure

Free Water Level

Oil pressuregradient

Water pressure

gradient

Pc = Po - Pw = g.h.( w- o)

Static pressures in a homogeneous reservoir

Gas pressuregradient

OWC

GOC

h


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As hydrocarbons accumulate, the largest pores are drained of water first(water is pushed out by buoyancy force of the hydrocarbon)

Effect of Texture & Pore Geometry - 2


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(water is pushed out by buoyancy force of the hydrocarbon).

Smaller pores are drained of water and displaced by hydrocarbon as theHC column (height or buoyancy pressure) increases

A

B

Capillary Pressure is measured in the lab by severalmethods. eg A brine saturated sample is displaced by a non wettingphase such as air through a porous plate at increasing pressures. Thismimics the displacement of water (in a water wet reservoir) by hydrocarbon


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Capillary Pressure curves

Irreducible S w


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Capillarypressuredirectly relatedto ht aboveFWL

Rock S is aseal due tohigh entrypressure

(S wirr )


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Capillary Pressure curves from variousfacies , Wheatstone-1


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If you know the FWL from pressure data and have a familyof cap pressure curves for various permeabilities and ameasurement (or estimate from logs) of the permeabilityin the formation you can calculate an S w profile (to

lib l l i )


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calibrate your log analysis)

These porositieseach have anassumed k(from /krelationship)

(each for different k)

SS w

Fluid Contacts can be estimatedfrom pressure data


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Fluid Contacts can be estimated from pressure data : egpressure data through gas pay, Wheatstone-1


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Chapter 5 (Reservoir Description)Lb13wS2a

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