Paper Caracterizacion

SECTION 2 RESERVOIR CHARACTERIZATION

WHY IS RESERVOIR CHARACTERIZATION NEEDED?EXPERT'S OPINIONS

"WF success is dependent on reservoir geology"

"Geology is never known as well as it needs to be known"

"Many WF fall below expectations because of the flaws in reservoir characterization”

"Most WF fail because of inaccurate reservoir characterization"

One needs to develop an in-depth qualitative understanding and an accurate quantitative de-scription of the reservoir state at the:

1. At the start of waterflood project2. At any time during the recovery process3. At the time of waterflood abandonment

The following features specify the reservoir state:

1. Pressure and Temperature

2. Rock PropertiesSpatial (3-D) description (mapping) of all reservoir and non-reservoir rock properties:

Lithology, Porosity, Permeability, Anisotropy, Compressibility, Heterogeneity Compartmentalization, Stratification, Faults, Fractures, Connectivity, Continuity Mechanical strength, etc.

3. Fluid PropertiesDetailed 3-D description of Oil, Gas, and Water properties:

Viscosity, Density, Solution Gas-oil ratio, Compressibility, Fluid distribution, Change of Composition with Pressure/Temperature variation, Injection water and Formation water interaction, etc.

4. Rock/Fluid Interactive PropertiesRelative Permeability, Capillary Pressure, Wettability, Water/Rock interaction, etc.

It should be clearly understood that accurate quantification of all of the above features is almost impossible.

S e c t i o n 2

Reservoir characterization is therefore a dynamic process, requiring continual updating and up-grading due to:

data becoming available only in a piecemeal manner,

data applicability and reliability is often uncertain and improves with time,

better interpretation techniques continue to become available,

newer insights are gained with time, and

unanticipated problems surface during the productive life requiring a different/fresh look.

No one discipline alone generates, manipulates, and utilizes all the above data. Hence, reservoir characterization is a multi-disciplinary effort. The following disciplines participate in the process:

Geophysics

Geology

Petrophysics

Hydrology

Reservoir Engineering/Production Engineering/Drilling Engineering/Facilities Engineering

Laboratory Specialists

A synergistic approach has proven efficient and productive, saving lots of time, effort, money, and subsequent finger-pointing between various disciplines.

The total scope of a reservoir characterization project is depicted in Figure 2-1.

2

R e s e r v o i r C h a r a c t e r i z a t i o n

RESERVOR CHARACTERIZATION

FLUIDSTypeCompositionDistributionContacts

HABITATDepthPressureTemperature

FABRICLithologyPorosityPermeabilityHeterogeneityWettabilityMechanical Properties

INTERNAL FEATURESFaultsFracturesCompartmentsStratificationContinuityConnectivity

INTERNAL FEATURESFaultsFracturesCompartmentsStratificationContinuityConnectivity

EXTERNAL FEATURESShape & VolumeBoundariesAquifers

Figure 2-1

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S e c t i o n 2

RESERVOIR HABITAT

A reservoir is a sub-surface, 3-dimensional rock body with special attributes such that hydro-carbons can accumulate. These attributes are:

Porosity - void space for the fluids

Permeability - interconnected pore space to provide flow communication

Trapping Mechanism - cap rock above and oil/water contact below/pinch-outs

Common reservoir rocks are formed of limestone, dolomite, and sandstone.

Reservoirs come in various shapes and sizes. The most common are:

Domes

Anticlines

Faulted Structures

Stratigraphic - unconformity

Stratigraphic - sand lenses, shoe-string sands

Reefs

These shapes influence the development/production process, not only during the primary depletion but also during the displacement type of IOR (Improved Oil Recovery) processes.

Traps with moderate to high relief are commonly developed under peripheral water injec-tion schemes.

Traps with low relief are generally developed under pattern flood schemes. Other factors may favor the pattern flood – low permeability, high heterogeneity, low well cost, shorter project life.

4


All reservoirs are under the influence of two PRESSURE sources:

Pore (Reservoir) Pressure

Overburden Pressure (or Rock External Overburden Stress)

POREPRESSURE

OVERBURDENPRESSURE

Figure 2-2

Three types of reservoir pressure systems are en-countered. These are shown below:

Normal Pressure Reservoir

PR = 0.46 x Depth

Abnormally High (Geo-Pressure) Reservoir

PR > 0.46 x Depth

Sub-Normal Pressure Reservoir

PR < 0.46 x Depth

(Note: Pressure Gradient of salty formation water is assumed at 0.46 psi/ft.)

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Oil

Water

Open System

Closed System

Oil

OilOil

S e c t i o n 2

PRESSURE - DEPTH PLOTSThe pressure gradient from a Pressure — Depth plot, such as one the shown here, is indicative of the type of fluid present as a continuous phase in the pore space of a reservoir.

Gas Gradient < 0.1 psi/ft

Oil Gradient = 0.3 to 0.4 psi/ft

Water Gradient > 0.434 psi/ft

The presence of more than one fluid in the reservoir is indicated by the change of pressure gradient. The intersection of pressure trends shows the posi-tion of the contact between the fluids.

RFT and MDT data (Schlumberger), SFT data (Halliburton), or FMT data (Baker Hughes) is extremely useful for this purpose.

6

0

100

200

300

400

500

600

700

800

900

1,000

1,100

1,200

1,000 psi 1,250 psi 1,500 psi 1,750 psi 2,000 psi

PRESSURE

DEP

TH

GEOSTATIC – ROCK PLUS FLUID (1.0)

15 POUND DRILLING MUD (.78)

SALINE WATER (.492)

FRESH WATER (.422)

HEAVY OIL (.404)

LIGHT O

IL (.251)

NATU

RAL G

AS (0.50) (0.05)


slope = .050 psi/ft.



Gas

SG = .12

Oil

SG = .87

Brine

SG = 1.14

DE

PTH

FLUIDCONTACT

SLOPEBREAK

FLUIDCONTACT

SLOPEBREAK

RESERVOIR TEMPERATUREReservoir temperature is obtained by:

1. Direct measurement using wireline thermometer2. Calculation from regional thermal gradient and known depth

A generalized Depth versus Temperature plot is shown below. The thermal gradient, slope of this curve, in most of the oil-producing areas of the world in the range of 1-2 degrees F per 100 ft of depth.

Temperature

Dep

th, f

eet

18,000

. 7

S e c t i o n 2

• During the primary recovery phase, reservoir temperature usually remains essen-tially constant. All reservoir processes are assumed isothermal.

• During a waterflood, three changes are brought about due to the injection of colder wa-ter in a hot reservoir.

1. The reservoir rock around the injection well gets colder. With continuous injection, the region of cooled rock expands outward away from the injector. The resulting ther-mal shock causes rock contraction, thereby inducing rock cracking and fractures in the reservoir.

2. High-pressure injection water increases pore pressure in the vicinity of the well and thereby decreases the in-situ stress level. This reduced stress level can be sufficient to cause shear failure of the rock and slippage of faults. As the water-front moves outward away from the injection well, the region of shear failure and fault slippage continues to grow.

3. Temperature decrease in the vicinity of the well results in a region of increased vis-cosity. This region expands as water front moves outward into the reservoir.

In many waterflood projects, continual improvement in well injectivity has been noted. Pres-sure transient well tests have confirmed presence of large negative skins and increased for-mation permeability.

The combined effect of the three is rather hard to predict without simulating the thermal and geo-mechanical behavior of the reservoir.

EFFECT OF STRESS CHANGE DURING A WF ON PERFORMANCEDuring a WF process, the effective stress (Poverburden - Preservoir) around an injector changes due to increase in reservoir pressure and a decrease in reservoir temperature. This change has re-sulted in one or more of the following changes in many WF projects:

1. Shear failure of rock resulting in hairline fractures

2. Elongation of existing fractures

3. Slippage of faults

4. Wellbore failure due to caving of wellbore wall and slipping of faults

In comparison, the effective stress increases due to decrease in reservoir pressure. This change has resulted in reservoir compaction and surface subsidence in many projects.

8


POROSITY

Porosity is the measure of the void spaces in a rock where fluids (oil, gas, and water) re-side under reservoir conditions of pressure and temperature.

Where: BV = Total Bulk Volume GV = Total Grain Volume PV = Total Pore Volume

Porosity is dependent upon rock type, grain size distribution, shape of grains and their ar-rangement, nature and degree of cementation, deposition history, and digenetic changes.

Rock Type Common Porosity Range, %

Limestone 3-12

Sandstone 12-28

Porosity may be defined on the basis of:

TOTAL: which accounts for all the available void space

EFFECTIVE: which accounts for only that void space which is interconnected and which participates in the fluid movement in the reservoir. All reservoir-engineering calculations are based on this value as it pertains to pore space of economic interest.

Figure 2-3 shows the type of porosity in a thin section.

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S e c t i o n 2

NON-EFFECTIVEPOROSITY

EFFECTIVE POROSITY

DEAD ENDPOROSITY

CEMENTINGMATERIAL

SAND ORLIME GRAINS

Figure 2-3

We need maps showing distribution of effective porosity under reservoir conditions of pressure, temperature, and stress.

METHODS FOR POROSITY MEASUREMENT1. Direct laboratory measurements on cores cut from the reservoir

2. Indirect calculation from physical measurement of a rock property (that can be corre-lated with porosity) using logs

DIRECT LABORATORY MEASUREMENTS Core samples of various sizes are used. Core plugs are used for homogeneous rocks

(sandstones, in general) while full size cores may often be used for limestone.

Direct measurements on cores in the laboratory under either reservoir conditions or room (bench-top) conditions.

For clean and dry cores, the following methods are used:

Saturation Method — the core sample is 100% saturated with a liquid of known density.

'Boyle's Law' Method — the simplest, the fastest, and the least expensive method.

10


Valve Valve

SampleChamber

ReferenceVolume Pressure

Gauge

PressureRegulator

To GasPressureSource

Valve Valve

SampleChamber

ReferenceVolume Pressure

Gauge

PressureRegulator

To GasPressureSource

Figure 2-4

The decision to duplicate reservoir conditions or room conditions in the laboratory de-pends on the nature of rock. If effective porosity is stress dependent (such as Rock C), reservoir conditions must be duplicated. If effective porosity is not stress dependent (such as Rock A), room condition measurement would be satisfactory.

AB

C

Net Pressure: PSI

Poro

sity

: Fra

ctio

n of

Orig

inal

0 2000 4000 6000 8000 10000

1.0

.8

.6

.4

.2

.0

Initial Porosity Description ΔPV/PV/PSI24% Well Cemented 3 X 10-6

28% Friable 15 X 10-6

33% Unconsolidated 40 X 10-6

ABC

Initial Porosity Description ΔPV/PV/PSI24% Well Cemented 3 X 10-6

28% Friable 15 X 10-6

33% Unconsolidated 40 X 10-6

ABC

Figure 2-5

Net Pressure = Overburden Pressure – Reservoir Pressure

. 11

Gas

S e c t i o n 2

POROSITY FROM WIRELINE LOGS Well logs are depth records of a physical property of the reservoir rock,

which can be related to porosity through some physical or empirical relationship.

Most common relationships relate Porosity to Density, Acoustic Velocity, and Neutron Population.

Comparison of log-derived porosity with core-measured porosity selects the logging tool that is best suited for a particular area.

There are various practical reasons for the choice of logging over coring.

1. Log measurements are under reservoir conditions of pressure, temperature, and stress.

2. Logging is cheaper and faster than coring. Hence, logs are run on all wells but only a small number of wells are cored.

3. Porosity information is available shortly after logging.

4. A continuous porosity profile is made available.

12


PERMEABILITY

Permeability is the measure of the ease of flow of fluids through the interconnected pore space.

It is the single most important property, since it governs the rate of fluid flow. Hence, the economics of a project.

Darcy's Law, an empirical relationship, provides the basis for quantifying permeability.

It relates flow rate through a porous medium to the properties of rock and fluid, and to the applied pressure differential, by the following expression:

L

q

A

Pi Po

q

Where: q = Flow Rate, cc/secK = Permeability, darcy Pi = Inlet Pressure, psig

PO = Outlet Pressure, psig = Fluid Viscosity, cpL = Core Length, cm

Reservoir permeability varies over a wide range.

Rock Type Permeability Range, MD Average, MD

Limestone 0.1-----200 10-100

Sandstone 10-----3500 50-250

Permeability is the property of the rock alone and is independent of the type of fluid so long as it totally fills the effective pore volume (100% saturation) and flows through the rock in a laminar manner.

Various methods are used for measuring permeability:

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S e c t i o n 2

1. Laboratory Measurement

2. Well Tests

3. Porosity - Permeability Correlations

4. Potential Logging Approach

LABORATORY MEASUREMENT Core samples of various sizes are used. Small plugs are used for a homogeneous rock

(sandstones, in general) while full size cores are used for a heterogeneous rock (limestone and dolomite).

Rock (Absolute) permeability is routinely measured in the laboratory under room pressure and temperature conditions. For stress sensitive cores, measurements must be made under effective reservoir pressure.

For routine measurements of permeability, an apparatus named Permeameter and shown in the figure below, is the apparatus commonly used.

Sample Holder

Calibrated OrificePressure Regulator

P1Upstream Pressure

P2Downstream Pressure

Figure 2-6

Gas (air, nitrogen, helium) is used as the test fluid as it is more convenient and tests are rapidly conducted. If water is used as the test fluid, formation water or synthesized brine is used.

14

Maximum

90° From Maximum


A full diameter core is used for horizontal and vertical permeability measurements.

Horizontal Permeability

K(x) – in a pre-selected direction (parallel to bedding plane)

K(90) – in the direction at 90 degrees to the pre-selected direction

Vertical Permeability

K(z) is measured in the direction per-pendicular to the bedding plane.

Oriented cores duplicating their geographical placement in the reservoir provide very important data on the directional permeability trends in a reservoir.

Through identification of permeability trends (grain orientation in clastic rocks and fractures, joints, fossil alignments in carbonate rocks) this data assists in in-jection/production wells placements to optimize sweep efficiency of a displace-ment project.

Many waterfloods fail due to the limited knowledge of the anisotropic character of the reservoir rock.

For stress sensitive rocks (friable, unconsolidated), laboratory measurements are made under simulated reservoir conditions of pressure (net overburden pressure). Since tem-perature has no significant effect, tests are made at room temperature.

Old Technology New Technology: Downhole Photos, Image Logs (FMI/FMS)

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S e c t i o n 2

PERMEABILITY FROM WELL TESTS Well tests are very important sources for permeability (Koh to be exact) values for a reser-

voir. The value is considered more representative as the well test is representative of a much larger portion of the reservoir than is a core.

The measurements can be easily interpreted into effective Koh (md-ft) of a reservoir within its radius of influence. The estimated value is valid under reservoir conditions of pressure, temperature, and saturations.

Common well tests are:

Pressure Build Up Pressure Fall off

Permeability data from well test analysis is continually integrated with that obtained from the core analysis data. The objective is to evolve a consistent reservoir description.

PERMEABILITY FROM WIRELINE LOGS No wireline log is available at the present time that directly measures permeability in a

reservoir.

Some newer tools such as NMR and CMR are currently under active research and de-velopment. They are proving promising in some applications; especially after the log re-sponse is conditioned to the available core data.

Whenever successful, significant savings will be realized in terms of cost and time.

16


FORMATION COMPRESSIBILITY

Reservoir rocks, just like reservoir fluids, are compressible and expand as pore pressure de-creases due to production and thereby provide a source of expulsive energy.

In reservoir engineering calculations, rock compressibility is reported on the pore volume ba-sis. Its value is obtained from:

Laboratory Measurements Correlations

Hall Van Der Knapp

In the oil reservoirs, total compressibility is given by:

Ct = Co So + CwSw + CgSg + Cf

when P > PBP

Ct = CQSw + CwSw + Cf

when P < PBP

gas compressibility dominates all others

rock compressibility is usually ignored Cr << CgCt = CgSg as Cg >> Co or Cw or Cf

In the aquifer, total compressibility is given by:

Ct = Cw + Cf

For most competent rocks, the value ranges between 2 – 20 x E–06 (1/psi). For unconsoli-dated rock, this value can exceed 100 E-6 (1/psi).

. 17

S e c t i o n 2

ROCK WETTABILITY

Wettability is the tendency of one liquid (oil or water) to preferentially spread over the surfaces of a rock, when two or more fluids (oil, gas, and water) are present together.

Gas is always the non-wetting fluid. Hence, it preferentially occupies the centers of the larger pores.

Reservoir rocks are made up of minerals (silica and carbonates) that are natively wa-ter-wet. Hence, all reservoirs should initially be water- wet.

Many reservoirs exhibit a large range of wetting tendency (from strongly water-wet to neutral-wet to strongly oil-wet); therefore, the change must have occurred some time after oil accumulation.

A number of possible reasons for the alteration have been suggested: (1) some crude oils contain surface-active ingredients and polar compounds, and (2) some are rich in asphaltenes and wax-like material.

In some reservoirs, wettability depends on structural position – high structural areas are often oil-wet; upper flank wells are of neutral wettability; areas closer to OWC are often water-wet.

CONTACT ANGLE is a common measure of rock wettability. It is measured in the lab-oratory by using samples of reservoir fluids and a crystal of the rock that makes up the pore surfaces in the reservoir. After equilibrium is established, the contact angle is measured through the water phase.

WATER-WET

βC

WATER

ROCK SURFACE

OIL

σOSσWS

σOW

βC

WATER

ROCK SURFACE

OIL

σOSσWS

σOW

βC

WATER

ROCK SURFACE

OIL

σOSσWS

σOW

βC

OIL-WET

βC

Figure 2-7

18


The contact angle scale below shows the ranges that classify rock wettability.

WATER WET INTERMEDIATE WET OIL WET

STRONGLYWATER-WET NEUTRAL

STRONGLYOIL-WET

0° 30° 60° 90° 120° 150° 180°

Most reservoir rocks exhibit intermediate wettability. However, many reservoirs exhibit strongly water-wet or oil-wet behavior.

A number of other laboratory techniques are also utilized. Amott's method is very popular - it uses a representative core that is either obtained under preserved conditions or is pickled with reservoir fluids for a long time to insure that native state is re-stored.

The method subjects the core to an imbibition-drainage process, which duplicates the reservoir processes of oil accumulation and waterflood displacement.

Accurate assessment of reservoir wettability is very important as it has a pronounced effect on:

1. Initial Distribution of Oil and Water2. Connate Water Saturation3. Fluid Flow through the Reservoir4. Residual Oil Sanitation5. Production Performance6. Formation Resistivity

1. INITIAL DISTRIBUTION OF OIL AND WATERThe solid surfaces in the water-wet rock are totally covered with a film of water. In addition, smaller pores are totally filled with water.

The solid surfaces in the oil-wet rock are totally covered with a thin film of oil. The smaller pores are still filled with water.

. 19

OIL WET

WATER WET

S e c t i o n 2

2. CONNATE WATER SATURATIONConnate water saturation in the water-wet rock is around 20 to 35% and around 5 to 15% in an oil-wet rock.

Sandstone

Water Wet Rock(Nugget Sand)

Oil Wet Rock(Springer Sand)

Water Saturation: Percent

Air

Per

mea

bilit

y: m

d1000

100

10

1.00 10 20 30 40 50 60

Figure 2-8

3. FLUID FLOW THROUGH THE RESERVOIRStrongly Water-Wet RockWater prefers to wet solid surfaces and thereby advances along the walls of the pore spaces. With continual advancement, it pushes oil from the edges until water cusps in at the pore exit. It then retains some oil as disconnected, isolated droplets in the pore centers. This oil saturation is called 'Residual Oil Saturation to Water - Sorw’.

Oil Oil Oil

Water Water Water

Figure 2-9

20


Strongly Oil-Wet RockWater prefers to move through the pore centers pushing oil ahead of it. With continual advance-ment, it drags oil from the edges until it establishes a continuous path through the pores. It then retains oil as a connected film covering the solid surfaces. This oil saturation is called 'Residual Oil Saturation to Waterflood - Sorw'.

Oil Oil Oil

Water Water Water

Figure 2-10

4. RESIDUAL OIL SATURATION TO WATERFLOODSorw for a water-wet rock is of the order of 25 - 40% and in the 30-45% for an oil-wet rock.

Sorw is not a function of water throughput or applied pressure differential for a water-wet rock, but is strongly dependent on the two for an oil-wet rock.

5. PRODUCTION PERFORMANCEThe idealized production performance (oil recovery and water-cut versus time) of a strongly wa-ter-wet and oil-wet reservoir is compared below.

Strongly Water-Wet Rock Large oil recovery prior to water breakthrough

Relatively small increase in oil recovery post breakthrough

Water-cut increases sharply after water breakthrough

Total oil recovery is essentially independent of the volume of water injected and the applied flooding pressure gradients

. 21

S e c t i o n 2

CUMULATIVE INJECTION, PVI

OIL

RE

CO

VE

RY

WA

TER

-OIL

RA

TIO

Figure 2-11

Strongly Oil- Wet Rock Lower oil recovery prior to water breakthrough

Substantial increase in oil recovery post breakthrough

Water-cut increases gradually after water breakthrough

Total oil recovery is dependent on the volume of water injected and the applied flooding pressure gradients

CUMULATIVE INJECTION, PVI

OIL

RE

CO

VE

RY

WA

TER

-OIL

RA

TIO

Figure 2-12

22


Waterflood recovery is dependent on rock wettabilityThe generalized plot of Expected Ultimate Recovery versus rock wettability shows that for simi-lar oil/water viscosity ratio floods, recovery is higher from a water-wet rock than an oil-wet rock. It also shows that recovery from a neutral-wet rock could even be higher than the two extreme cases.

EU

R, %

OO

IP

CONTACT ANGLE0 90 180

Figure 2-13

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S e c t i o n 2

FLUID DISTRIBUTION IN A RESERVOIR

One of the most important factors responsible for the success of a waterflood is the fluid satura-tion (oil, water, gas) and their distribution in the reservoir at the start of the project.

Saturation distribution is seldom known (except under the initial conditions prior to production) and its accuracy is always a suspect. There are many reasons for this:

1. Initial static distribution is not exactly known, especially in a mixed lithology reservoir.

2. Reservoir development prior to waterflood is not uniform. Hence, the production perfor-mance is varies both areally and vertically. Regional drift of fluids inside the reservoir is hard to quantify.

3. Even with a dedicated effort, the sampling inadequacy poses a major handicap.

Since this information is essential as the starting point in a waterflood project, it has to be ob-tained with reasonable degree of accuracy. Resources required are: a multi-disciplinary team, a dedicated effort, and commitment of time, money, and resources.

At the start of waterfloodEstimate of saturation averages is rather straightforward. However, it requires that:

1. good estimates are available for pore volume and original oil-in-place,

2. accurate production records have been kept,

3. water influx rates can be estimated with accuracy, and

4. reservoir drive mechanisms can be assessed. Classical reservoir engineering methods are employed.

The average oil saturation in the reservoir at the start of a WF is primarily related to the pri-mary drive mechanism, as shown by the figure below:

24


100

80

60

40

20

00 10 20 30 40 50 60

Remaining Oil Saturation, %

Recovery Efficiency, % OOIP

Res

ervo

ir P

ress

ure,

% O

rigin

al P

ress

ure

1 Liquid and Rock Expansion2 Solution Gas Drive3 Gas Cap Expansion4 Water Influx5 Gravity Drainage

100 90 80 70 60 50 40

1 2 3

4

5

Figure 2-14

Mapping of saturations is possible if:

1. A history-matched reservoir simulation model is available. Accuracy hinges on reservoir description, however.

2. A well logging program is the best approach. Key wells are selected and appropriate logs are run to calculate saturation distributions around producers.

3. Coring of new wells is another approach. However, the coring program (cutting, retrieval, preservation, storage, testing) has to be designed such that meaningful interpretation is possible.

. 25

S e c t i o n 2

FLUID DISTRIBUTION IN A RESERVOIR UNDER INITIAL (STATIC) CONDITIONSThe simplified (idealized) model below depicts the initial distribution of fluids in a reservoir.

ClosureGas-oil contact

Oil-watercontact

GAS

WATERWATER

Gas cap

Oil zoneOIL

Trailing Edge

Leading EdgeSpill point

OWC LEADING

GOC

OWC TRAILING

Figure 2-15

This distribution is controlled by equilibrium between the gravitational and capillary forces.

Gravitational Force: It causes fluid segregation into gas above, oil in the middle and wa-ter at the bottom.

Capillary Force: It causes the wetting fluid (water in general) to occupy the smaller pores while the non-wetting fluids (oil and gas) occupy the larger pores.

A realistic model of Depth vs. Water Saturation is shown in the figure below:

26


OIL-WATERTRANSITION

ZONE

GASTRANSITION ZONE

GAS

DEPTH

WATER

0 100

PC

SWSWC

OIL

Dry Oil-Water Contact (@Sw = Swc)

Producing Oil-Water Contact (@Sw = 1 – Sorw)

Initial Oil-Water Contact (@Pc = Threshhold Value)

Figure 2-16

The length of oil-water transition zone is a function of pore size distribution. If pores are of uniform size (higher permeability reservoirs), transition zone length is very small. For a wide pore size distribution (lower permeability reservoirs), transition zone may cover the entire reservoir thickness.

The oil-water transition zone is of great interest in designing a waterflood project.

There is no single definition of oil-water contact (OWC). An arbitrary choice is made de-pending upon the local practice and the purpose of the analysis.

NOTE: Capillary Forces have a major effect on initial distribution of water in the reser-voir. HOWEVER, they will have minimal effect on water movement during a waterflood where viscous forces and high Pressure Gradients dominate.

. 27

S e c t i o n 2

Methods used for establishing initial fluid distribution are:

1. Direct Method

Production testing: well is production or DST tested over successively known depth intervals

2. Indirect Methods

Coring: conventional core analysis is of limited use.

Logging: resistivity and porosity logs are used.

RFT/MDT: spot pressures are measured at known depths along the well path. Only fluid contacts are established.

Laboratory Capillary Pressure Tests: representative preserved cores are used to measure capillary pressure - water saturation data utilizing the following methods:

Porous Diaphragm Method

Mercury Injection Method

Centrifuge Method

Test is made under conditions that duplicate the reservoir process of interest - Drainage or Imbibition.

Drainage: The wetting phase fluid is displaced from the pores by the non-wetting fluid (Initial oil migration in the reservoir).

Imbibition: The non-wetting phase fluid is displaced from the pores by the wet-ting phase fluid (waterflooding in a water-wet reservoir).

28


CAPILLARY PRESSURE DATA FOR WATERFLOODING

Waterflooding results in increasing water saturation in the reservoir as oil is displaced.

The laboratory-derived capillary pressure curve measured under the condition of increasing wet-ting phase saturation is called "Imbibition" and is the data that is needed as input to reservoir simulator to model the waterflood process.

The figure below shows a typical imbibition capillary pressure curve for a water displacement process in rocks with different wettability preferences.

INTERMEDIATE WETTABILITY ROCK

ForcedImbibition

Drainage

PC

= P

O-P

W

SWSWC Sorw

SpontaneousImbibition

10

Figure 2-17

. 29

S e c t i o n 2

STRONGLY WATER-WET ROCKWF in a water-wet rock is an Imbibition process as Sw increases.

PC

= P

O-P

W

SWSWCSorw

10

Figure 2-18

STRONGLY OIL-WET ROCKWF in an oil-wet rock is a Drainage process as So decreases.

PC

= P

O-P

W

SW Sorw

10

SWC

\Figure 2-19

30


RELATIVE PERMEABILITY

Relative permeability curves are the 'road maps' to production rate and hydrocarbon recovery. Hence, it is of paramount importance that data is as representative as possible.

Reservoir pore space is generally filled with two (oil and water) or with three fluids (oil, water and gas). Flow of any one fluid in the presence of other fluids is treated by the concept of relative permeability.

Relative permeability is defined as the ratio of the Effective Permeability to a fluid to the Abso-lute Permeability of the rock. The value ranges between 0 and 1 (or 0 to 100%).

This is the most important key data for all calculations dealing with water drive reservoirs, wa-terflood projects, and water coning - Hence, it is imperative that the data used is reliable. The following guidelines are recommended.

1. Either use a preserved core or make sure that wettability is re-stored in the laboratory.

2. Either use the reservoir live fluids (cumbersome) or use fluids with laboratory oil-water viscosity ratio matched to the reservoir condition viscosity ratio.

. 31

S e c t i o n 2

OIL-WATER RELATIVE PERMEABILITYA typical oil-water relative permeability relationship is shown in the figure below:

Sw, Water Saturation

Rel

ativ

e P

erm

eabi

lity

to O

il

Rel

ativ

e P

erm

eabi

lity

to W

ater

0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0

1.0

0.9

0.8

0.7

0.6

0.5

0.4

0.3

0.2

0.1

0

SWC Sorw

Kro

Krw

Figure 2-20

Swc = Connate (Irreducible) Water Saturation

Sorw = Residual Oil Saturation (where Kro = 0) at Swmax (Maximum Water Saturation)

(Krw)Sorw = End Point Relative Permeability to Water

(Kro)Swc = End Point Relative Permeability to Oil

32


Since hysteresis plays an important role, the relative permeability is also influenced by the direc-tion of change. The figure below is a typical example of this behavior.

DRAINAGE

0 20 40 60 80 100

RE

LATI

VE

PE

RM

EA

BIL

ITY

, %

WETTING PHASE SATURATION, %PV

IMBIBITION

100

80

60

40

20

0

Figure 2-21

The water (wetting phase) relative permeability is generally not direction dependent - it is a function of its saturation alone.

The oil (non-wetting phase) relative permeability is highly direction dependent. At any given water saturation, it is lower for the imbibition process than for the drainage process.

Many times hysteresis effect is not modeled in reservoir simulations.

METHODS OF MEASUREMENTSRelative permeability data is measured in the laboratory by one of the following methods: Un-steady State Method, Steady State Method, and Centrifuge Method.

These testing methods differ from each other in the quantity and quality of the generated data, and therefore in the time required and the cost incurred.

. 33

S e c t i o n 2

Important Details of Direct MethodsUnsteady State Method

The experimental procedure is depicted below. Here, water is injected into a 100% saturated (with oil and connate water) core at a constant pressure differential. The oil and water produc-tion rates are continually measured until only the injected water is produced.

Constant Δ P

Oil & WaterWater

Pi Po

Figure 2-22

Advantage: Takes only a few hours to complete the test.

Disadvantage: Calculations to convert production data into relative permeability data are involved.

Steady State (Penn. State) Method

The experimental procedure is depicted below. Here, water and oil at a known ratio are in -jected into a 100% saturated (with oil and connate water) core until saturation and pressure differential across the core stabilize. This step is repeated with different known oil and water in-jection ratios.

OilWaterWater

Pi Po

Oil

Figure 2-23

Advantage: Calculations to convert production data into relative permeability are simple.

Disadvantage: This procedure takes a long time.

34


Centrifuge MethodThis is a much faster method. It measures relative permeability of the phase that is produced during the test.

GRADUATED COLLECTOR

FLOW LINE

CORE

COMPRESSIONWASHERS

SLEEVE

GRADUATED COLLECTOR

FLOW LINE

CORE

COMPRESSIONWASHERS

SLEEVE

Figure 2-24

Comparison of the Methods1. Water-oil relative permeability data from the steady state method covers the entire range of

saturation change.

2. Since the saturation range is Limited in the unsteady-state method, extrapolation of the data is needed.

3. Data obtained from the centrifuge method is about the same within the experimental accuracy.

4. Agreement between gas-oil relative permeability data from gas- flood and centrifuge method is quite good.

5. The centrifuge data provides a better estimate of residual liquid saturation as the dis-placement process may be subjected to higher pressure gradients.

. 35

S e c t i o n 2

WATER SATURATIONR

ELA

TIV

E P

ER

ME

AB

ILIT

Y

100

10

1.0

0.1

0.01

OIL

WATER

STEADY-STATEMETHOD

UNSTEADY-STATEMETHOD

0 20 40 60 80 100

Figure 2-25

The steady-state method is generally considered to be superior to the other two methods.

36


Rock wettability has a pronounced influence on the shape of the relative permeability curves and on the end-point values. Figure below demonstrates this.

Strong ly Water - Wet Rock

Strong ly Oi l - Wet Rock

. 37

WATER SATURATION, %PV

RE

LATI

VE

PE

RM

EA

BIL

ITY

, FR

AC

TIO

N

1.0

0.8

0.6

0.4

0.2

0WATER

OIL

WATER SATURATION, %PV

RE

LATI

VE

PE

RM

EA

BIL

ITY

, FR

AC

TIO

N

1.0

0.8

0.6

0.4

0.2

0

WAT

ER

OIL

0 20 40 60 80 100

S e c t i o n 2

Maintaining a core in its native (un-altered) state for SCAL laboratory tests is very important. While it is a pains-taking activity and an expensive undertaking, it is absolutely essential to the accuracy of recovery forecasting (project performance) and the project profitability.

The Extraction process - where core is cleaned off its oil and water and dried - may alter the native wettability of the core.

The Restoration process - where the extracted cores are saturated with water and oil - may partially restore the wettability character. Restoration may get better if the core is aged with time.

EXTRACTED

RESTORED

PRESERVED

KRW

Figure 2-26

OIL-GAS-WATER RELATIVE PERMEABILITYSimultaneous flow of oil, gas, and water occurs at only a small combination of saturations due to the mobility (K/ µ) contrast between the fluids. The fluid distribution is rapidly arranged as:

WATER OIL BANK GASW/O O/G

Rel Perm Rel Perm

38


A typical three-phase diagram is shown below:

Figure 2-27

Laboratory tests to obtain this data are very cumbersome and expensive. Hence, a number of 'probabilistic' models have been developed to estimate three-phase data that is needed for the reservoir simulation studies. These models (Stone’s Correlation) require the routinely available two-phase water-oil and gas-oil relative permeability data.

Important Details of Indirect Methods:Data f rom Analogous Reservoi r

A fairly good source if similarity of reservoir type, depositional setting, fluid properties, and development strategy is established.

Publ ished Corre la t ions

Many published correlations (between relative permeability and capillary pressure) are avail-able. Their use is highly questionable.

. 39

S e c t i o n 2

Fie ld Product ion His tory

Production history of a reservoir can also be utilized in estimating the field average or well aver-age effective permeability relationship, provided the drive mechanism is well understood. Its use is however limited because the data becomes available after the fact.

CAUTION!!!

Fluid flow behavior and oil recovery estimate are a direct function of the relative permeability relationship.

One must make sure to utilize the relationships which are obtained from carefully designed laboratory tests on cores which are known to maintain wettability character during the coring, shipment, storage, and testing processes.

CURRENT THOUGHTS ON OIL-WATER RELATIVE PERMEABILITY MEASUREMENT Steady-State method is better than the Unsteady-State method as it provides data over the

entire saturation range.

Unsteady-State method results in too high residual oil saturation because of insufficient flooding.

The Centrifuge method provides a better estimate of the residual oil saturation.

SHELL recommends a combination method where Steady-State method provides rel-ative permeability data and Centrifuge method provides the residual oil saturation.

Relative permeability should be made under reservoir conditions using imbibition procedure on representative preserved or restored-state (aged?) cores.

In the past, non-preserved cores were often used. These cores generally exhibited water-wet behavior due to changes introduced during coring, retrieval, storage, and testing pro-cesses. Field examples below show significant changes in the residual oil saturation values, suggesting higher displacement efficiencies.

Current Old Brent 15% 28% Dunlin 15 25 - 30 Schiehallion 14 29 San Fran-cisco

10 >=40

Lekhwair 5 28 Maui 10 28

Volumetric sweep efficiencies need re-assessment in older waterfloods where displacement efficiencies were based on older estimates of residual oil saturations.

40


RESERVOIR HETEROGENEITY

A

B

C

Figure 2-28

Sealing or Non-Sealing Faults?

High or LowPermeability?

Fractures?

Localized vs. Regional Features

Pay vs. Non-Pay?

Vertical Communication?

ReservoirQuality Varies?

Aquifer Extent?

Layer 7Layer 7OWC

Layer 6

Layer 6

Layer 5

Layer 1

Layer 2Layer 3

Layer 4

Layer 5

Layer 6

Figure 2-29

. 41

S e c t i o n 2

Heterogeneity is the spatial variation of the reservoir properties. It can occur at various levels.

Large Scale Heterogeneity may be due to:

Reservoir Compartmentalization

Presence of Faults

Presence of Fracture clusters

Large Permeability Contrast

Small Scale heterogeneity is due to:

Shape and size of the sediments

Deposition history of the sediments

Subsequent changes due to digenesis and tectonics

Heterogeneity is the most difficult attribute to quantify; but has the greatest effect on the effi-ciency of the WF processes.

While all reservoir properties may vary, both areally and vertically, change in permeability values are most drastic (many fold changes are encountered).

Therefore, vertical heterogeneity is in general much greater than areal heterogeneity.

Permeability Porosity

Depth Depth

Figure 2-30

42


Two methods were introduced during the 40's and 50's for the quantification of vertical heterogeneity on a scale of 0 (homogeneous) to 1.0 (heterogeneous). These are:

1. Lorenz Coefficient

2. Dykstra & Parson’s Permeability Variation Factor

These were utilized in estimating vertical sweep efficiency of a WF project.

Areal heterogeneity was handled by conventional interpolation and extrapolation methods, such as:

1. The Assumed Trends

2. The Inverse Distance Method

3. The Inverse Distance Squared Method

Currently, numerous geostatistical techniques are being employed.

GEOSTATISTICAL TECHNIQUESThe conventional technique for mapping a property value is to contour the known values and/or the estimated values, while incorporating geological trends, depositional features, and per-sonal experience of the user. Hence, these techniques are highly subjective.

The newest technique with a great deal of promise and non-subjectivity is geostatistical treat-ment. It uses spatial correlations (variograms are relations of measured values quantifying variation with distance and direction) to estimate the value of the property at all XYZ locations. Additional soft data is incorporated honoring geological trends, depositional features, and personal experience of the user.

. 43

S e c t i o n 2

RESERVOIR COMPARTMENTALIZATION – ITS ASSESSMENT

Many reservoirs are compartmentalized into separate blocks. Each block may have its own oil-water contact and may contain an oil of different composition than the other blocks.

Barriers such as faults shown below may divide the reservoir into blocks that:

May not communicate with one another at all, or

May not communicate at the beginning but may start communicating under the produc-tion-induced pressure differentials between the blocks.

Top–Brent structure mapPLATFORM

Top–Brent structure mapPLATFORM

Figure 2-31

The project economics is impacted if compartmentalization information is not correct. Initial development planning (number of wells and their locations and surface facilities requirements) is dependent on this.

Initially, only the static data of various kinds is available. It must be analyzed to gain some insight into the inter-block communication. Later on, dynamic (pressure and production) data becomes available which is far more conclusive.

44


The commonly employed methods are described below in detail.

1. RFT/MDT data

These data provide gas gradients in the gas cap, oil gradient in the oil leg, water gradi-ent in the water leg, and depth of free water level in each block.

2. PVT data

The oil density data under reservoir conditions (from PVT analysis) is compared from wells in various blocks. The difference in density at similar depths can only exist if there is no inter-block communication.

3. Well Test Data

Interpretation of long-term pressure drawdown/buildup test yields information on the presence of lateral barriers within the well drainage radius. While such information is non-unique, inferences may be drawn.

4. GC Fingerprinting

Oil samples from various wells are analyzed for C10 - C12 components. These analy-ses are compared statistically using cluster analysis to look for similarities and differ-ences between blocks.

5. Oil Maturity Indexing

Both oil samples and solvent-extracts of cores are analyzed for geo-chemical attributes that are related to hydrocarbon maturity. These attributes are compared to look for similarities and differences between the blocks.

6. Residual Salt Analysis (RSA)

The salts present in the non-preserved conventional cores are leached out by ultra-pure distilled water and analyzed for 87SR/86SR isotopic ratio. Difference in ratios indicates compartmentalization.

7. Fault Seal Modeling

Normalized Displacement – ratio of fault displacement to reservoir thickness – is computed for each fault from the seismic data to determine what portion of sands are in communication across the fault.

Note:

All single source evaluations provide only a partial answer due to their individ-ual limitations of areal coverage and measurement sensitivity. Hence, integra-tion of partial answers is needed to fully evaluate compartmentalization.

Accurate assessment is possible only after dynamic data becomes available.

. 45

S e c t i o n 2

VERTICAL HETEROGENEITY - LORENZ COEFFICIENT

List the data (k, ) fore each interval of thickness h. Calculate kh and h and arrange in a de-scending kh order. The following quantities are then calculated.

1. Cumulative Fractional Pore Volume (h / htot)

2. Cumulative Fractional Flow Capacity (kh / khtot)

A linear scale plot of 2 vs. 1 is made (shown below).

Lorenz Coefficient, L = Area ABCA / Area ADCA

HOMOGENEOUS HETEROGENEOUS

0 L 1.0

Fraction of Total Volume, hΦ

Frac

tion

of T

otal

Flo

w C

apac

ity (k

h)

1.0

0.8

0.6

0.4

0.2

00 0.2 0.4 0.6 0.8 0.1

C

B

A

Figure 2-32

The value of L for the successful floods is in the range of 0.2 to 0.4

46

1.0

D


VERTICAL HETEROGENEITY - PERMEABILITY VARIATION: VDykstra & Parson introduced a statistical measure of reservoir heterogeneity and correlated it with Vertical Sweep Efficiency.

List data (k) for each sample. Arrange in descending order of permeability (k). For each value, calculate the % of number of values that are larger. Plot Perm vs. "% higher" on log probability paper & fit straight line. Such a plot is shown below.

HOMOGENEOUS HETEROGENEOUS

0 L 1.0

Portion of Total Sample Having Higher Permeability

Sam

ple

Per

mea

bilit

y, M

D

1 2 5 10 20 30 40 50 60 70 80 90 95 98 99 99.5

1008060

40

20

1086

43

2

1

k

kσ

k - kPermeabilityVariation,V k

10-3 = = 0.710

k

Figure 2-33

This correlation was developed for California sandstone reservoirs and is applicable in a range of mobility ratio floods at various stages (at various water-cuts) in stratified reservoirs. It is widely used for this purpose in conventional forecasting of volumetric sweep efficiency of waterflooding.

Both L and V values are non-unique since various property distributions can result in the same numerical value.

. 47

S e c t i o n 2

Note:Ordering of property values in descending or ascending order is not reflec-tive of real situation. Hence, this method should not be used for layering the reser-voir for flow calculations.

The figure below shows:

On the right, the actual permeability profile of a reservoir

On the left, the permeability profile arranged in ascending order

Depth Depth

k kFigure 2-34

It is obvious that the two representations will manifest different behavior in a WF project.

It should be noted that for STATISTICAL PURPOSES, often different permeability zones are ar-ranged in descending k-h order (descending permeability if each zone is defined by the same thickness, h) in order to calculate cumulative permeability thickness, or cumulative flow contribu-tion. For example, to set-up Lorenz and Dykstra-Parsons calculations, zones must be ordered like this.

48


AREAL HETEROGENEITY

Areal heterogeneity has been handled by conventional interpolation and extrapolation means. These are described below:

THE ASSUMED TRENDS METHODProperty distribution is contoured on the basis of a known trend. It is quite an effective method in the hands of a person who is well versed in the regional depositional Trends.

THE INVERSE DISTANCE METHODThe unknown value is estimated on the basis of weight factors associated with the entire data set. The weight factors are calculated such that the influence of a known data point is inversely proportional to its distance from the point of the unknown value.

Where: dj = distance between the measured value and location of interestn = number of nearby points i = weight factor

VX = unknown value at point x

. 49

S e c t i o n 2

THE INVERSE DISTANCE SQUARED METHODThe unknown value is estimated on the basis of weight factors associated with the entire data set. The weight factors are calculated such that the influence of a known data-point is inversely proportional to the square of its distance from the point of the unknown value.

Σλi = 1

NOT PENETRATED

NOT COMPLETED

PERFORATIONS

Figure 2-35

50


RESERVOIR CONNECTIVITY & PAY CONTINUITY & FLOODABILITY

Reservoir continuity and pay connectivity are the two most important factors that control displacement processes such as waterflooding.

Figure 2-36 shows two major problems in a waterflooding project, especially in lenticular and flu-vial reservoirs.

Possible indicators of these problems include:

Poor Inter-Well Correlation

Low Net to Gross Thickness Ratio

Lower than expected Well Injectivity or Productivity

Large Difference in Reservoir Pressure from PBU & PFO Tests

Quantitative assessment is difficult at best because of the directional nature of flow. The concept of floodable pay is demonstrated below:

Figure 2-36

Floodable Pay A: Pay that completely participates in the flood. All the available pore space is contacted by the encroaching fluid.

Partially Floodable Pay B: Pay that partially participates in the flood. Some of the pore space is not contacted and the resident hydrocarbons are partially trapped by the encroaching fluid.

Non-Floodable Pay C: Pay that does not effectively participate in the flood process. The resident hydrocarbons remain essentially trapped and unrecovered.

The pay continuity is quantified by the following Equation:

. 51

A

Li

ΦiHi

B

C

S e c t i o n 2

There are two common methods for establishing the pay continuity in a reservoir. These fall un-der two categories:

1. Tracer tests

2. Multiwell pressure interference tests

A tracer used in a waterflood project should meet most of the following criteria: safe, easy to handle, environmentally friendly, water soluble, essentially insoluble in oil, non-adsorbent on rock and metals, chemically inert, detectable in small amounts, inexpensive.

Tracers used are of the following types: (1) water soluble Alcohols, (2) inorganic salts such as Ammonium, Sodium, Potassium, (3) fluorescent dyes, and (4) Radioactive substances such as Tritiated water.

Single well pressure (PBU/PFO) tests and multi-well pressure (Pulse/Interference) tests are the best way to assess zonal connectivity and connectivity, to locate fractures/faults, and to assess directional property trends in a reservoir.

There are many ways to establish reservoir continuity qualitatively, once reservoir data is avail-able and production trends are established.

1. Regional Pressure and Production Trends

2. Ratio of OOIP estimate from Volumetric and MBE

If this ratio is = 1, all pay is participating.If this ratio is < 1, some pay is isolated and not participating.

3. Ratio of EUR (estimated ultimate recovery) from a simulation model study (utiliz-ing a history-matched model) and the decline curve analysis.

If the two values are close, all pay is participating. If simulation estimate is greater than the decline curve analysis, some pay is not connected to the producing wells.

Continuity/connectivity between two wells can be quantitatively measured and plotted versus the horizontal distance. Figure 2-37 below shows such a relationship for the Means San Andres reservoir (under a pattern waterflood earlier and now under a pattern CO2 - Flood) in West Texas.

52


HORIZONTAL DISTANCE BETWEEN WELLS - FEET

PE

RC

EN

T C

ON

TIN

UIT

Y

0 1000 2000 3000 4000 5000 6000

FLOODABLEPAY

CONTINUOUSPAY

1320

'

2640

’

3960

’

5280

’

100

80

60

40

20

0

Figure 2-37

Note:Sands may not be correlative between wells, but they may still be connected (in the 3-D pore space).

FLOODABILITYFloodability of pay is a very important aspect in a WF process. To be floodable, a pay interval must be:

1. Continuous between injector and producer

2. Injection supported

3. Effectively completed in a producer

Hence, all the continuous pay is not necessarily floodable.

The two-well schematic below illustrates the difference between continuity and floodability.

. 53

S e c t i o n 2

RESERVOIR CONTINUITY = 67 %

RESERVOIR FLOODABILITY = 17 %

INJE

CTI

ON

SU

PP

OR

TED

= 3

3%

CO

MP

LETE

D =

50%

PRODUCER INJECTOR

A

B

C

D

E

F

G

Figure 2-38

Layers A, D, F, and H are geologically continuous. They together contain 2/3 of the inter-well pore volume.

Layers C and H are injection supported.

Layers D and H are completed effectively in the producer.

Layer H is the only one that is effectively floodable.

54


EMPIRICAL LAWS OF HETEROGENEITY

1. All reservoirs are heterogeneous in rock and fluid properties

When we know little about them, we assume them to be homogeneous

2. The more we get to know them, the more heterogeneous they become

Heterogeneity is proportional to the amount of time, effort and money spent

3. Heterogeneity has major impact on reservoir risks and uncertainty related to:

Volumes of hydrocarbons-in-place

Recovery Efficiency

Well Productivity

Reservoir Performance

4. Unless you walk a mile or two along the outcrop of the reservoir formation, you will have little appreciation of rock heterogeneity

. 55

S e c t i o n 2

HYDROCARBON CLASSIFICATION

Hydrocarbons are classified with respect to their state under the reservoir Pressure and Tem-perature conditions. Surface conditions (P & T) are also considered when classifying the production.

Hydrocarbon systems in the reservoir are divided into five main categories;

1. Dry Gas

2. Wet Gas

3. Gas Condensate

4. Volatile (high shrinkage) Oil

5. Black (low shrinkage) Oil

A simple sub-division on the basis of solution gas-oil ration is given below.

BLACK OIL

GAS CONDENSATE

VOLATILE OIL

WET GAS

Original Gas-Liquid Ratio SCF/BBL Stock Tank Liquid

Bubblepoint Systems Dewpoint Systems

Nea

r C

ritic

al

DRY GAS

100 1000 10000 100000

Figure 2-39

Black Oils and Volatile Oils are candidates for a WF project. A volatile oil requires more serious consideration due to its nature of rapidly changing into gas when pressure falls below the bubble point pressure.

Gas reservoirs (dry, rich, or condensate) are never intentionally waterflooded, as a large fraction of the gas is left trapped in the reservoir due to the water-wet nature of the rock.

56


CANDIDATE RESERVOIRS FOR WATERFLOODING

DryGas

Reservoir

WetGas

Reservoir

RetrogradeGas

CondensateVolatile

Oil

Under SaturatedBlack

Oil

SaturatedBlack

OilHeavyOil/Tar

PROJECTS COUNT

Gas Saturation: 100% 100% 100-70% 0-60% 0-30% 0% 0%

Figure 2-40

. 57

S e c t i o n 2

PHASE BEHAVIORClassification of a Multi-Component System

WFTARGET OILS

GAS

TEMPERATURE

PR

ES

SU

RE

Separator

Volume %Liquid

CriticalPointC

Cricondenbar (T)

F

Near – Critical Phase - Behavior

Cric

onde

nthe

rm(M

)

8%

20%

40% L

iquid

60%

80%90%

100% Bubble Point Locus

Dew Point Locus

Figure 2-41

58


DefinitionsBubble Point Curve: The locus of the points of pressure and temperature at which the first bubble of gas is formed in passing from the liquid to the two-phase region.

Dew Point Curve: The locus of the points of pressure and temperature at which the first droplet of liquid is formed in passing from the vapor to the two--phase region.

Two-Phase Region: That region enclosed by the bubble point line and dew point line wherein gas and liquid co-exist in equilibrium.

Critical Point: That state of pressure and temperature at which the intensive properties of each phase are identical. Also, the junction of the bubble point and dew point curve.

Critical Temperature: The temperature at the critical point.

Critical Pressure: The pressure at the critical point.

Iso Vol or Iso Volume Lines (quality lines): The loci of points of equal liquid volume percent within the two-phase region that intersect at the identical point..

Saturation Pressure: Bubble point pressure (for liquid systems) or dew point pressure (for gaseous systems).

. 59

S e c t i o n 2

BLACK (LOW SHRINKAGE) OIL

Temperature

Pre

ssur

e A RESERVOIR

B RESERVOIR

C SEPARATOR

Gas

Critical pointLiquid

Bubb

le-p

oint

Lin

e

Dew-

poin

t Lin

e

A

BC

Mole % Liq100

75

50

25

Conditions Critical point lies to the right of the Cricondenbar Quality Lines are closely spaced near the Dew Point line

Production Behavior During Pressure Depletion Produced fluids in the separators are in two phases

Substantial amount of liquids recovery GOR <1,000 SCF/STB Oil Gravity < 45 API Color is black to dark brown/green

Producing GOR continues to increase with time, as shown on the right

Oil gravity decreases gradually during most of the producing life. Later in the life (when the producing gas becomes wet), gravity increases due to the addition of gas condensate to the oil

Production Behavior During WaterfloodingWaterflood projects have been initiated at various pressure levels ranging between A and B. Their performance differs from one another.

60

GO

R

TIME

°API

TIME


VOLATILE (HIGH SHRINKAGE) OIL

Temperature

Pre

ssur

e A RESERVOIR

B RESERVOIR

C SEPARATOR

Gas

Critical pointLiquid

A

BC

Mole % Liq

50

100

75

25

Conditions Critical Point lies to the right of the Cricondenbar Reservoir temperature is closer to the Critical temperature

Production Behavior During Pressure Depletion Produced fluids in the separators are in two phases

Low liquid recoveries GOR <1,750 SCF/STB Oil Gravity 40 Degrees API Some color FVF > 2 RB/STB

Producing GOR increases with time but far less than for the Black Oils

Oil gravity increases gradually with the addition of condensates from the gas into the produced oil phase

Production Behavior During WaterfloodingWaterflood projects have been initiated at various pressure levels rang-ing between A and Bubble Point Pressure (or not very far from there).

. 61

°API

TIME

GO

R

TIME

S e c t i o n 2

Oil Oil Oil

Expanded gasPreviously released

Released gasD

CB

Released gas

Released gas

Released and greatlyexpanded gas

Oil produced to surfaceundergoes pressure andtemperature reduction

Reservoir pressureDeclines with production

EF

+ +

x100

Temperature

Pre

ssur

e

E

F

D

C

B

A

Δp Δp

P0

P1

P2

P3

P4

P0P1 P2

P4P3

TATA TA

TATemp

Temp TM

TM

Figure 2-42. Volume Relationship for a black oil system.

62


PVT PROPERTIES OF BLACK OIL

Rs

Rsi

PipbP

PipbP

Bo

PipbP

μo

SOLUTION GAS-OIL RATIOSCF/STB

OIL FORMATION VOLUME FACTORBBL/STB

OIL VISCOSITYPOISE

RS = volume of gas produced at surface at standard conditionsvolume of oil entering stock tank at standard conditions

BO = volume of oil + dissolved gas leaving reservoir at reservoir conditionsvolume of oil entering stock tank at standard conditions

. 63

S e c t i o n 2

Relationship Between Surface & Reservoir Conditions

OILSHRINKAGE

SOLUTIONGAS

FREEGAS

EXPANSIONWATER

SHRINKAGE

SOLUTIONGAS

OIL

OIL WATER

WATER

FREEGAS

SOLUTIONGAS

FREEGASSURFACE CONDITIONS

14.7 PSIA, 60°f

BOTTOMHOLE CONDITIONS

= PR, TR

Figure 2-43

64


• Oil Formation Volume Factor = Bo Units: BBL / STB

This is the volume in BBL that one STB of oil and its dissolved solution gas (Rso) occupies in the reservoir at P and T.

• Water Formation Volume Factor = Bw Units: BBL/STB

This is the volume in BBL that one STB of water and its dissolved solution gas (Rsw) occu-pies in the reservoir at reservoir P and T.

• Gas Formation Volume Factor = Bg Units; CF/SCF

This is the volume in Cubic Feet that one Standard Cubic Feet of gas occupies in the reser-voir at reservoir P and T.

• Solution Gas-Oil Ratio - Rs Units; SCF/STB

This is the volume of gas in SCF that is dissolved in one STB of oil under reservoir P and T.

• Two-phase Formation Volume Factor = Bt Units: BBL/STB

Bt = Bo + (Rsi - Rs) Bg

This in the volume in the reservoir (P&T) that is occupied by one STB of oil and its dissolved gas (P&T) plus the free gas evolving out of the oil due to pressure drop from Pb to P.

. 65

S e c t i o n 2

OILFIELD WATERS

FORMATION WATERThe naturally occurring water in the reservoir pore space at discovery is called the formation wa-ter or the interstitial water. Since it has been associated with the particular reservoir rock and crude oil over a long period of time, it is in the state of complete chemical equilibrium.

INJECTION WATERInjection waters are procured from various ground and underground sources.

Ground Water; Sea, River, Lakes

Underground Water: Shallow Aquifers, Recycled Produced water from oil reservoirs

Four properties of interest are:

1. Dissolve Salts (TDS in parts per million)

Cations: Na +, K+, NH4+, Ca++, Mg++, Ba++, Sr++, Fe++

Anions: Cl-, Br-, OH-, HCO3-, CO3--SO4--, BO2--, CO3--, PO4--

Fatty Acids: Formic, Acetic

2. Dissolved Gases – CO2, H2S, CH4, O2

3. Suspended Solids of various sizes and concentration.

4. pH Value

Below are illustrative examples of various waters from a Saudi Arabian project.

Ions Arab-DProduced

Water

WasiaAquifer

Ras. TanuraSea Water

Sodium 26,339 2,206 13,200Calcium 6,668 560 516Magnesium 1,228 116 1,690Sulfate 648 1,099 3,240Chloride 55,263 3,800 23,700Carbonate 0 0 6Bicarbonate 433 206 103Hydroxide 0 0 0Total dissolved solids 90,580 7,987 42,500

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WATER PROPERTIESThe following physical properties are of interest:

1. Density of Water is 1.0 gm/cc (350 Pound/BBL)

2. Amount of Dissolved Natural Gas in Water, Rsw

Solubility of natural gas in water is quite low Average of 10 to 20 SCF/STB

3. Formation Volume Factor of Water, Bw

Assume equal to 1.0 RBBL/STB

4. Compressibility of Water, Cw

5. Viscosity of Water

2.0

1.8

1.6

1.4

1.2

1.0

0.8

0.6

0.4

0.2

00 50 100 150 200 250 300 350

21

3

4

viscosity of saline water (60,000 ppm) and temperature

Curve 1, at 14.7 psia; 2, at 14.2 psia

3, at 7100 psia; 4, at vapor pressure

TEMPERATURE, F

AB

SO

LUTE

VIS

CO

SIT

Y, C

P

4.0

3.6

3.2

2.8

2.460 100 140 180 220 260

TEMPERATURE, F

CO

MP

RE

SS

IBIL

ITY

OW

WA

TER

, cw

x 10

1 vV P Tcw =

100020003000400050006000

1.3

1.2

1.1

1.00 5 10 15 20 25

GAS-WATER RATIO, Cu Ft/Bbl

RA

TIO

:S

OLU

TIO

N C

OM

PR

ES

SIB

ILIT

YW

ATE

R C

OM

PR

ES

SIB

ILIT

Y

CORRECTION FOR GAS IN SOLUTION

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S e c t i o n 2

CHEMISTRY OF WATER MOVEMENT THROUGH THE RESERVOIR

As the injection water (varying concentration of dissolved salts) moves through the reservoir, it contacts the formation water and hydrocarbons.

Stripping takes place and water picks up some light ends, CO2 and H2S, as shown in the figure below.

OIL

WATER

CO2 H2S C1

C2

C3

WATER-SOLUBLE COMPONENTS ARE REDISTRIBUTEDBETWEEN THE OIL AND WATER PHASES

WATER IS INJECTED TOMAINTAIN PRESSURE ANDDISPLACE OIL

OIL AND WATERARE PRODUCED

Figure 2-44

Solubility of natural gas in water is a function of temperature, pressure and TDS.

68


24

20

16

12

8

4

060 100 140 180 220 260

TEMPERATURE, F

SO

LUB

ILIT

Y O

F N

ATU

RA

L G

AS

IN W

ATE

R, C

U. F

T/B

BL

5000 PSIA

4500

4000

35003000

2500

2000

1500

1000

500 PSIA

0 10 20 30

1.00.90.80.7

0.6

0.5

0.4

0.3

0.2

0.1

Sol

ubili

ty o

f nat

ural

gas

in b

rine

Sol

ubili

ty o

f nat

ural

gas

in p

ure

wat

er

Total dissolved solids, %

250°200°100°50°

150°

Figure 2-45

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S e c t i o n 2

ROCK AND FLUID PROPERTIES FOR AN IDEAL WATERFLOOD PROJECT

1. Homogeneous and Non-Fractured Reservoir

2. Non-Partitioned, Isotropic (Kx = Ky), and Continuous Pay

3. High Porosity & Permeability Rock

4. Low Permeability Contrast between Layers

5. High Ky/Kh Ratio for High Relief Structures

6. Low Kv/Kh Ratio for Flat Structures

7. No Water Sensitive Clays

8. Water-Wet Rock

9. High Transmissibility between Flanks and Center (for Peripheral Injection Scheme)

10. High Oil Target

11. Low Oil Viscosity

12. Reservoir Average Pressure Higher than Bubble Point Pressure (No Free Gas Saturation)

13. Thick Oil Column with Small Oil-Water Transition Zone

14. Low Initial Water Saturation in Oil Column

15. Minimal Gas Saturation in Oil Column

16. No Gas Cap

17. Availability of Injection Water

18. Quality of Water

19. Chemical Compatibility between Waters & Oil

20. On-Shore Location

70


CASE STUDY NO. 1 CHANGE IN GEOLOGIC CONCEPTS FORCE A CHANGE IN WATERFLOOD PLAN

PayOld Geologic ConceptContinuous Pay

Prod. Prod.

Inj.

Oil-Water Contact

The San Andres carbonate reservoir in the Denver Unit in Wasson San Andres field, Texas was produced at 40-Acre well spacing under the solution gas drive recovery scheme. A water-flood project was thereafter initiated to increase oil rate and recover additional oil.

Based on the initial geological concept that reservoir is continuous with a common OWC, water was injected below OWC in the edge wells. Water was expected to move laterally in the aquifer and push oil vertically upwards.

The peripheral waterflood did not perform as expected:

1. IPR (injection-production ratio) could not be sustained, as injectivity in the edge wells was low due to lower ‘Kh’.

2. Oil response was erratic; some up-dip wells showed rate gain while others did not ex-perience any pressure or rate increase

A detailed geologic study incorporating pressure-production data showed that pay zones are not only discontinuous (not floodable on the 40-Acre well spacing) but also have different OWC's.

Based on the new geological concept, the peripheral plan was modified into a pattern flood and in-fill wells were drilled on 20-Acre well spacing.

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S e c t i o n 2

Current Geologic ConceptNon-Continuous Pay

Pay

New Pay

Prod. Prod. Inj.Inj. Inj.

The pattern flood had a great success. After the waterflood reached its economic limit, a CO2-flood was initiated and the well spacing was further reduced to 10-Acre spacing. It is cur-rently an ongoing successful EOR project.

72


CASE STUDY NO. 2NEW TECHNOLOGY AIDS RESERVOIR CHARACTERIZATIONPeripheral water injection in the Ghawar Arab-D reservoir, Saudi Arabia, efficiently displaced oil from the flanks of the reservoir to the crestal producers, until water breakthrough occurred in an erratic manner in some flank wells while others in similar structural locations continued to pro-duce dry oil. This is depicted in the figure below.

No hard data was there to indicate faults and fractures in the reservoir. No well had ever crossed a fault, and well tests had not positively identified any fault or major discontinuity. In ad-dition, there was a common belief (miss-belief) that faults in limestone and dolomite reservoirs cannot exist and will heal up if induced.

DRY OIL AREA

INITIAL OWCCURRENT OWC

WATERUNDERRUNNING

FRACTURECLUSTERS

WATERED-OUTAREA

FLOOD FRONT

FAULTS

To match flood fronts and water-cut history in wet wells, reservoir simulation models of the 1960 through 1980's resorted to dramatically increasing rock permeability in localized areas arbitrar-ily. These models resulted in good history-matches (of course), but their forecasts deviated badly from performance data on flood front and water production.

In the late 1980's and early 1990's, 3-D seismic surveys and Image Log data positively con-firmed for the first time the existence of fracture clusters and faults in the reservoir. The newer simulation models, based upon the geological models that incorporated faults and fracture clusters in the reservoir maps, matched history with only minor changes and produced fore-casts that were in good agreement with the performance data.

PROBLEM NO. 1Oil reservoirs A, B, and C, shown in the figure below, share a common aquifer and are in hy-drodynamic equilibrium.

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S e c t i o n 2

How would you classify these pressure systems at discovery?

Normal Pressure

Geo Pressure (Abnormal)

Sub-Normal Pressure

AB

C

SURFACE

PROBLEM NO. 2RFT pressure data has been collected in an infill well in a stratified sand/shale reservoir. Interpret this data for the effect of the shale layers on reservoir flow continuity. What other infor-mation can you deduce?

74


gradient = 0.09 psi /ft




– 6500

– 6550

– 6600

– 6650

– 6700

– 6750

– 6800

– 6850

A

B

C

D

E

F

3140 3160 3180 3200 3220 3240 3260 3280

PRESSURE (PSIG)

DE

PTH

(SS

–FT

)

PROBLEM NO. 3Estimate oil-water contact in the reservoir shown below. The available data is:

1. The discovery well A found full oil (oil gradient = 0.35 psi/ft) column with pressure of 400 psig at 450 ft ss.

2. The first delineation well B was wet (water gradient = 0.45 psi/ft) with pressure of 1,750 psig at 1,800 ft ss.

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S e c t i o n 2

0

500

1000

1500

2000500 1000 1500 2000

X

? OWC

B A

PROBLEM NO. 4Below are Samples taken from 5 different layers in a reservoir, one sample is taken from each layer.

Samples were taken from 3 different wells

1) Average the data and develop a semi-log Permeability - Porosity correlation for the entire reservoir.

2) Should you use one Permeability - Porosity correlation for the entire reservoir?

Well #1 Well #2 Well #3

Interval PorosityThicknessh (ft) k(md) k(md) k(md)

5 0.05 0.1 0.2 0.2

10 0.10 1 0.8 0.5

30 0.15 10 3.2 1.2

25 0.20 100 12.6 3.0

10 0.25 1000 50.0 7.5

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PROBLEM NO. 5 & 6Below are Samples taken from 5 different layers. Samples have been analyzed from each layer. 3 different rock types with different Perm-Porosity relationships (the same Porosity in this example is used for simplicity) have been developed for this reservoir.

1) Determine the Lorenz Coefficient of Heterogeneity for each rock type.

2) If these rock types can be identified easily in different areas of the field, then which areas will make the best candidate for Waterflooding?

Well #1 Well #2 Well #3

Interval PorosityThicknessh (ft) k(md) k(md) k(md)

5 0.05 0.1 0.2 0.2

10 0.10 1 0.8 0.5

30 0.15 10 3.2 1.2

25 0.20 100 12.6 3.0

10 0.25 1000 50.0 7.5

For PROBLEM #6

1) Determine the Dykstra Parsons Coefficient of Heterogeneity for each rock type. Make the as-sumption that each sample represents a sample for every foot of pay. (In other words, for Rock #1 there 10 samples of 1000 md perm, 25 samples of 100 md perm, etc.)

2) COMPARE THESE RESULTS WITH THE NUMBERS OBTAINED FROM THE LORENZ CALCULATIONS AND IDENTIFY ANY KEY DIFFERENCES. PROBLEM NO. 7An irregular shaped sand body, shown below, is to be water flooded.

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S e c t i o n 2

INJECTOR PRODUCER

B

Identify the following sand bodies:

1. Attic oil

2. Dead Ends (Trapped) oil

3. Floodable oil

PROBLEM NO. 8Estimate permeability value at the observation well X from the data given on four of the wells in a waterflood pilot, by using all conventional methods.

B

AC

D

400

1,000

200

1,500

1.0 km

0.75 km

0.5

km

X 0.4 km

78


PROBLEM NO. 9Calculate continuity percent between Wells 1 and 2 in the reservoir with the stratification shown below:

12

3

10

10 10

20

20

20

Φ = 0.2

Φ = 0.1

Φ = 0.3

Φ = 0.2

0 2,500’ 5,000’

What will be the benefit of drilling Infill Well 3 on the continuity percent?

PROBLEM NO. 10Red Reservoir, Average Relative Permeability Characteristics

Two samples having porosity values of 12.3% and 22.7% have been tested to determine their water-oil relative permeability characteristics. These are provided on the attached Data sheet.

Questions

1. What definition of absolute permeability was used to prepare these curves?

2. For the sample with 22.7% porosity, what are the effective permeabilities to oil and water at a water saturation of 49 percent?

3. Does the rock from which these samples were obtained appear to be water-wet or oil-wet?

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S e c t i o n 2

Laboratory Relative Permeability Results

Sample 3A

Porosity (frac) = 0.227Air Permeability (md) = 23.8Permeability to Oil at Swir (md) = 21.4

Sw Kro Krw0.231 1.000 0.0000.318 0.680 0.0200.404 0.430 0.0450.491 0.250 0.0780.577 0.120 0.1300.664 0.050 0.1900.750 0.000 0.280

Sample 7C:

Porosity (frac) = 0.123Air Permeability (md) = 5.3Permeability to Oil at Swir (md) = 4.5

Sw Kro Krw0.350 1.000 0.0000.423 0.700 0.0150.496 0.500 0.0500.569 0.330 0.0800.642 0.160 0.1100.715 0.060 0.1900.789 0.000 0.300

80

Sample 3A

0.00

0.20

0.40

0.60

0.80

1.00

0.00 0.20 0.40 0.60 0.80 1.00

Water Saturation (fraction)

Rela

tive

Perm

eabi

lity Kro

Krw

Sample 7C

0.00

0.20

0.40

0.60

0.80

1.00

0.00 0.20 0.40 0.60 0.80 1.00

Water Saturation (fraction)

Rela

tive

Perm

eabi

lity Kro

Krw


PROBLEM NO. 11Calculate injection water requirement for maintaining average reservoir pressure at 3,000 psig and temperature of 100°F in order to provide for voidage replacement balance, at the time when oil production rate is 5,000 STB/Day, gas production rate is 10 MMSCF/Day, and water production rate is 1,000 STB/Day.

Fluid properties and given below:

Oil Formation Volume Factor = 1.2 RB/STB Gas Formation Volume Factor - 0.001 RB/SCF

Water Formation Volume Factor = 1.0 RB/STBSolution GOR at 3,000 psig & 100°F = 500 SCF/STB

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