Post on 16-Oct-2020
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Artificial Oil Recovery Enhancement
Methods
Dr.M.Helmy Sayyouh
Professor and Chairman
Petroleum, Mining, and Metallurgical Department
Cairo University
April, 2004
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CONTENTS
Chapter 1 Introduction to Heavy Oils
Chapter 2 Reserve Estimation and Classification
Chapter 3 Rock and Fluid Properties for ORE
Chapter 4 Non-Thermal Recovery Methods
Polymer Flooding
Caustic-Emulsion Flooding
Micellar-Polymer Drive
Miscible Fluid Displacement
Chapter 5 Thermal Recovery Methods
Steam Flooding
Cyclic Steam Stimulation
In Situ Combustion
Chapter 6 Bio-Chemical Methods
Chapter 7 North Ward Estes Field-Case History
Artificial lift in Egypt
Chapter 8 Reservoir Management
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Chapter 1
Introduction
Heavy oil and tar sands are important hydrocarbon resources that are destined to
play an important role in the oil supply in the world. The heavy oil resources of the
world total about 10 trillion barrels. In USA, heavy oil production is nearly 60% of
the total EOR production. Approximately 25% of the oil production of Canada is
from oil sands. Tar sands (oil sands) are reservoirs containing crude bitumen. The
world bitumen resources are more than 4 trillion barrels and are located principally
in Canada, 60%; Venezuela, 25%; and USSR, 14%.
The important question is: how much of this oil is recoverable and what techniques
could be applied? In order to produce oil from tar sands through wells, a large
amount of heat is needed to reduce the bitumen's viscosity. Recovery from
California heavy oil reservoirs by steam injection is about 55% of the initial oil in
place. In Alberta, recovery is considerably lower – 5 to 25% - because the main
recovery method is cyclic steam stimulation. Venezuela has nearly two trillion
barrels of heavy oil. Cyclic steam stimulation has been very successful in Venezuela.
In the case of heavy oil and tar sands, the recovery factor varies greatly ( from a
fraction of a percent to 80% ) from area to area, depending on the oil and the
reservoir characteristics, as well as the technique used. Viscosities of the heavy
crude's are varies from 100 to 1000 cp at reservoir temperature, while the viscosity
of the oil sand is greater than 1000 cp at reservoir temperature. Heavy crude's
contain 3 wt% or more sulphur, 10 – 30% asphaltenes, and as much as 2000 ppm of
vanadium compounds.
Geology is the single important factor determining the success of a heavy oil
recovery project. Large permeability variations would imply highly uneven
distribution of the injected fluid. Given the geological description of an interval, it is
possible to devise an injection scheme that would utilize the injected fluids to the
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greatest advantage. An important aspect of heavy oil recovery by thermal
techniques is the interaction of rock minerals and the injected fluids.
1-Heavy Oil and Tar Sands Deposits
Heavy oil and tar sands are important energy sources, currently making a
significant contribution to the overall energy supply of the USA and Canada. Heavy
oil and tar sands are petroleum or petroleum-like liquids or semi-solids occurring in
porous formations.
A generalized classification of heavy oil considers an association of : (a) low API
gravity-less than 20º, (b) high viscosity at reservoir temperature, (c) poor reservoir
mobility, (d) dark color, (e) sulphur content greater than 3%, (f) about 500 ppm
metal content, (g) up to +50% weight asphaltene content. A method presented by
Yen has been used to distinguish the pseudo-ternary composition and origin of
heavy oils.
Some examples of heavy oil reservoirs in the world are presented in Table 1.
Table 1 Example of Heavy Oil Reservoirs
cp ,Estimated Viscosity Oil Gravity Country Field
Gela Italy 8-13 80-220
Duri Sumatra 20 25
Darius Iran 12-20 --
Harbur Oman 18 -23 --
Karatchok Syria 19 – 23 --
Bati Raman Turkey 12.5 650
Jopo Venezuela 8 6200
Cold Lake Canada 10-12 100,000
Kern River USA, Texas 14 4,200
Midway Sunset USA, California 14 1600
UKCS-3 UK 11 – 15 150 - 2750
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Table 2 summarizes the estimated heavy oil and oil sands resources in the world.
Table 2 Heavy oil resources in the world
Recoverable Oil In Place Oil
(Million bbls) (Million bbls)
Canada 2,950,000 213,210
USA 77,160-127,000 30,065
Venezuela 700,000 – 3,000,000 500,000
Europe 13,196 1,406
Africa 25,700 1519
Middle East 50,000 – 90,000 4,680 Oman, S.A., and
Kuwait not included.
USSR and Asia 1,131 31
These data of Tables 1 and 2 show that heavy oil is widespread geographically and
that volumes in place approach that of conventional oil. Recovery factors from
heavy oil reservoirs are not good guide to their potential since they are production
process dependent. In the North Sea the heavy oil reservoir potential is linked
through economic considerations to reservoir size, geometry, water depth, as well as
reservoir rock and fluid properties.
2-Chemical Methods
A polymer flooding is suited for reservoirs where normal water floods fail due to
one of the two reasons: High Heterogeneity and High oil water mobility ratio.
Polymer floods mainly target oil in areas of the reservoir that have not been
contacted efficiently. Thereby, they reduce the detrimental effect of vertical
permeability variation (causing low vertical sweep) and facies variation (causing low
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areal sweep) on recovery efficiency.
The target of surfactant flooding is to lower the residual oil saturation in the pore
space contacted by the injected fluid. This is brought about mainly due to the
lowering of the oil-water interfacial tension.
3-Miscible Methods
These aim at achieving miscibility by eliminating the interface between injected
fluid and residual oil through a process of mass transfer between the two fluids.
Total elimination of capillary retentive forces at the injection crude oil interface has
given birth too many miscible processes. These eliminate the residual oil saturation
and thereby maximize displacement efficiency. Miscibility is dependent on reservoir
P&T and on the compositions of the injected fluid and crude oil. The first-contact
miscibility is achieved when the injected fluid and the crude oil mix in all
proportions and result in single phase mixtures. The multi-contact miscibility is
achieved due to the gradual transfer of molecules between the injected fluid and the
crude oil, thereby eliminating capillary forces completely.
4-Thermal Methods
Steam flooding is a multi-well, pattern derive process. When steam is injected, a
steam saturated zone forms around the injection well, and further beyond there is a
zone containing condensed steam. The temperature in the steam zone is the steam
temperature, declining as one move away from the well. Steam injection rate is an
important factor, since a high rate can cause early steam breakthrough, while a low
rate leads to heat loss. The temperature increase may cause an increase in the
relative permeability to oil. Gravity override of steam becomes important in thick,
permeable sands. The presence of a gas cap would further promote gravity override
of steam. The water zone thickness is an important factor. A thick water zone would
act as a heat sink, while thin water sand may heat the overlying oil. In a typical
steam flood, at the start of production, the water cut decreases and the oil cut
increases. Recovery factor is often lower than 50 %.
Cyclic steam injection is a single well process and involves the injection of steam for
several weeks (2 to 6 weeks) at the highest possible rates, often above fractures
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pressures in order to minimize heat losses. The well is then shut-in for several days
(3 to 6 days) to allow the steam to condense. Following the soaking phase, the well is
put under production. The efficiency of the shut-in or "soak" period duration is
questionable. A long soaking period results in a loss of production, while a short
period prevents adequate steam condensation.
In Situ combustion process is a pattern flood process. A small portion of the oil in
place is burned establishing heat to the rock and its fluids. A burning front and
combustion zone is propagated to the producing well by air injection into a well
(forward combustion). In the reverse combustion process, a burning zone is
propagated from oil producing well to an air injection well. This process was
developed as a method for recovering extremely heavy crude oils and has been
unsuccessful in the field. More heat is recovered if water is injected with air (wet
combustion). Wet combustion is a modified form of forward combustion. A
modification of the basic process is oxygen fire flooding which involves injecting
oxygen or oxygen enriched gas into the reservoir. The oxygen floods conducted so
far have either failed, or have performed no better than conventional fire floods
5- Bio-Chemical Recovery Methods
During the last ten years scientific and engineering efforts in the laboratories of
King Saud University (Saudi Arabia) and Cairo University (Egypt) has established
the basic start for Microbial Enhanced Oil Research technology in the Arab World.
It is expected that Microbial Enhanced Oil Recovery (MEOR) may recover up to
30% of the residual oil under the Arab reservoir conditions. The actual recovery,
however can only be determined through laboratory and pilot tests under field
conditions. A new technology should be developed to apply MEOR successfully.
6-Artificial Lift Methods
Artificial lift is to use additional energy, other than natural energy, to produce fluids
to the surface. The decision of which artificial system to use, depends on the
reservoir pressure, well depth and potential, and properties of the produced fluids.
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Chapter 2
Reserves Estimation
and Classification
Introduction
Field reservoir engineer is responsible for the estimation and classification of
reserves.
:quesEstimation techni
Material balance calculations
Sweep efficiency analysis
Decline curve analysis
Reservoir simulation
All reserves estimates involve some degree of uncertainty.
Why Reserve Estimates? Measure effectiveness of exploration and development.
Budgeting for drilling and facilities.
Unitization and MER determinations.
Purchase / sale of properties.
Bank loans.
Taxation.
Government policy and planning.
Definition
are estimated quantities of crude oil, condensate, natural gas, natural gas Reserves
liquids, and associated substances anticipated to be commercially recoverable:
- from known accumulations,
- under existing or anticipated economic conditions,
- by established operating practices, and
- under current or anticipated government regulations.
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In place CalculationOriginal Oil and Gas
Volumetric
OOIP or OGIP = (Rock Volume) x (Porosity) x (1 – Water Saturation)/ (Formation
Volume Factor).
Material Balance
Expanded volume of original reservoir fluids =
(Volume of withdrawals fluids) - (Volume of injected fluids)
Recovery and Efficiency Calculations
ft-ft and MCF/acre-STB/acre :factorsRecovery
fractional recovery of OOIP or OGIP :Recover efficiencies
:Methods of estimation
- Analogies
- Correlations
- Water flood design charts
- Material balance programs
- Reservoir simulation
Analogy Method
The analogous reservoirs should be similar to:
. Drive mechanism
. Permeability and porosity
. Well spacing and pattern
. Size
. Relative volumes of oil, gas and aquifer
. Degree of permeability and porosity heterogeneity
. Net-to-gross sand ratio
. Production practices
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. Depositional environment and trapping mechanism
. PVT properties
Recovery factor adjustments are made to compensate for differences between the
analogous reservoirs and the reservoirs being evaluated.
Correlations
:Depletion Drive Gas Reservoirs
Recovery Efficiency =1 - Pa Zi / Pi Za
Oil Reservoirs: Depletion Drive
1. During under saturated stage:
Recovery Efficiency = Ce (Pi-Pb)Boi/Bob
Where: Ce= (SoCo +Sw Cw +Cp)/So
2. During saturated stage:
Er = 0.41815 (Φ (1-Sw)/Bob)˙¹ x (k/1000μob)˙¹(Sw)·³(Pb/Pa)˙²
:Water Drive Gas Reservoir
Err= (1-PaZi/PiZa) + ((PaZi/ PiZa) EvEd)
Where: Ed= (1-Swi-Sgr) (1-Swi)
Sgr= 0.62 -1.3 Φ
Water floods
Mobility Ratio
M = (Krw/μw) x (Kro/μo)
Recovery Efficiency
Er = Ea x (Swb – Swi)/ (1-Swi)
Areal sweep efficiency, Ea, from a homogenous 5-spot water flood for a certain M
can be obtained from charts.
Ultimate Recovery
:Volumetric with Recovery Efficiency
Ultimate Recovery = Er x OOIP or OGIP (from volumetric)
:Material Balance with Recovery Efficiency
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Ultimate Recovery = Er x OOIP or OGIP (from material balance.)
Decline Curve Analysis Ultimate recovery is the sum of cumulative recovery to date and remaining reserves.
Remaining reserves can be calculated with decline curve analysis.
Reservoir Simulation
Reservoir simulation incorporates a comprehensive application of physical laws
governing multiphase fluid flow in porous media.
:step process-Reservoir simulation can be summarized in three
1. Setting up mathematical equations that describe fluid flow.
2. Solving the Mathematical equations.
3. Setting up the numerical model.
Reserves Classification
are estimated quantities of crude oil, condensate, natural gas, natural gas Reserves
liquids, and associated substances anticipated to be commercially recoverable:
- from known accumulations,
- under existing or anticipated economic conditions,
- by established operating practices, and
- under current or anticipated government regulations
: depending on, some degree of uncertaintyAll reserves estimates involve
The amount and reliability of geologic and engineering data available at the time of
the estimates.
Interpretation of these data
Milestones in Reserves
Definitions
1944: Frederic Lahee (API)
1955: Frederic Lahee (WPC)
1960: American Petroleum Institute
1962: Jan Arps (SPE)
1965: SPE
1972: V .E. Mckelvey (USG Survey)
1981: SPE
1985: SPE
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1987: SPE World Petroleum Congress(WPC)
1987 SPE- Endorsed Definitions of Reserves.
Reserves in General
1. Known or discovered accumulations.
2. Estimated volumes: crude oil – condensate – natural gas – natural gas liquids –
associated substances such as sulfur and carbon dioxide.
3. Based on interpretation of geologic and engineering data.
4. Commercially recoverable under economic, operating and regulating condition.
5. Time dependent (production).
6. Involve degree of uncertainty.
7. Subject to revision.
Methods of Classifying Reserves
:Ownership1.
Total – Gross – Net
:Recovery Mechanism2.
Primary - Improved
:Degree of Uncertainty3.
Proved – Probable – Possible
:atusDevelopment St4.
Developed – Undeveloped
:Productive Status5.
Producing – Non-producing
Proved Reserves
oil and gas reserves are the estimated quantities of crude oil, natural gas, and Proved
natural gas liquids which can be recoverable:
- in future years
- from known reservoirs
- under exiting economic and operating conditions.
A confidence level of 90 to 100% is required.
:Proved reserves must have
:includes The area of a reservoir which
- that portion delineated by drilling and defined by GOC and / or OWC
- the adjoining portions not yet drilled but economically productive
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.processThe facilities to
:Proved reserves have been divided into
Proved Developed Reserves: are expected to be recovered through exiting wells with
exiting equipment and operating methods.
Proved Undeveloped Reserves: are expected to be recovered from new wells on
undrilled acreage or from existing wells where a major expenditure is require for
recompletion.
Probable Reserves
are less certain than proved reserves and they are more likely to Probable reserves
be recovered than not under mid-trend economic conditions.
A confidence level of 50 to 90% is required.
:oProbable reserves have been divided t
Reserves representing the primary recovery from the delineated area of a :1Class
known reservoir.
: Reserves representing the primary recovery which depends on: Class 2
med for proved or probable of the reservoir beyond the limits assu extension a. Lateral
class 1 reserves due to up dip or down dip extensions.
adjacent to the delineated area of a known reservoir. fault blocks b. Undrilled
offsets to spacing units having proved or probable class1 or diagonal c. Direct
reserves.
Reserves representing the primary recovery dependent upon the development :3s Clas
of new reservoirs (not yet produced or tested) within the area of assigned proved
reserves. Class 3 reserves occur in a new reservoir overlying or underlying a proved
reservoir.
Incremental reserves where an alternate interpretation of actual or anticipated :4Class
performance or volumetric data indicates more reserves than can be classified as
proved or probable class1 to 3.
ble through the application, Additional quantities likely to be recovera :5Class
expansion or modification of improved recovery techniques.
Possible Reserves Possible reserves are less certain than probable reserves and can be estimated with a
low degree of certainty.
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Insufficient to indicate whether they are more likely to be recovered than not under
high-trend economic conditions.
A confidence level of 20 to 50% is required.
:Possible reserves have been divided to
area of a primary recovery from the delineatedReserves representing the :1Class
known reservoir.
: Reserves representing the primary recovery which depends on: Class 2
of the reservoir beyond the limits assumed for proved or probable extension a. Lateral
class 1 reserves due to up dip or down dip extensions.
adjacent to the delineated area of a known reservoir. fault blocks Undrilledb.
to spacing units having proved or probable class1 or diagonal offsets c. Direct
reserves
Reserves representing the primary recovery dependent upon the development :3Class
within the area of assigned proved tested)yet produced or (notreservoirs new of
reserves. Class 3 reserves occur in a new reservoir overlying or underlying a proved
reservoir.
ted Incremental reserves where an alternate interpretation of actual or anticipa :4Class
performance or volumetric data indicates more reserves than can be classified as
proved or probable class1 to 3.
Additional quantities likely to be recoverable through the application, :5Class
expansion or modification of improved recovery techniques.
Problems in Reserve Classification
Frontier Areas
1. No analogous reservoirs.
2. Sparse subsurface control.
3. Remote from market.
4. High operating costs.
Heavy and Extra Heavy Crude
Thermal stimulation is required and its response is highly variable.
Possible Future Development in Reserve Classification
A. Matrix to describe geologic uncertainty and feasibility of commercial extraction.
B. Inclusion with reserves of geologic and engineering bases for estimate.
C. Quantification of probabilities associated with reserve classifications.
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Chapter 3
Rock and Fluid Properties
The essential rock properties in EOR processes are those that govern the rock’s
storage capacity and spatial distribution; its ability to conduct fluids; and its spatial
and directional distributions
Porosity
Porosity is a measure of a rock’s storage capacity.
In EOR, we are primarily interested in interconnected pore space (effective
porosity).
Effective porosity is a dimensionless quantity, defined as the ratio of interconnected
pore volume to the bulk volume.
In an idealized arrangement of grains of uniform size the maximum porosity value
is 47.64% for cubic packing, and the minimum is 25.96% for rhombohedra packing
(Fig.1-3)
In the flow equations, porosity appears as one of the parameters that scales the
volume of fluids present in the reservoir at any time.
During production, this volume is depleted, and reservoir pressure drops. The
higher the reservoir’s porosity, the less this pressure decline will be over time
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Fig.1-3 Porosity for cubic and rhombohedra packing
The special case in which porosity does not appear in the flow equation is the single-
phase incompressible flow system. In such a flow system, there is neither
accumulation nor depletion, and so porosity vanishes.
In the other extreme, there are reservoirs in which porosity changes with pressure,
and so appears in the equation as a function of pressure rather than as a constant
value.
Permeability
Absolute permeability is a measure of a rock’s ability to transmit fluid. Permeability
is analogous to conductivity in heat flow.
Since it is a measure of resistance to flow, a higher permeability reservoir
experiences less pressure drop than a corresponding low permeability reservoir.
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Permeability varies widely in naturally occurring reservoirs, from a fraction of a
mD to several Darcie’s.
Similar to porosity, the permeability of a reservoir could be a function of pressure.
Permeability is a key parameter controlling the propagation of transients created by
conditions imposed at the well.
It does not determine ultimate recovery, but rather the rate of this recovery.
Homogeneous vs. heterogeneous systems
Homogeneous systems feature uniform spatial distribution, while heterogeneous
systems exhibit non-uniform distribution.
Reservoir Fluid Properties2 -3
Fluid properties, like rock properties, significantly affect fluid flow dynamics in porous
media.
Unlike rock properties, however, fluid properties exhibit significant pressure dependency.
The properties of interest in the gas flow equation are:
Density appears in the gravity term, and it is often neglected.
The compressibility factor introduces an important non-linearity, in that it appears in the
formation volume factor.
Gas viscosity is also strongly dependent on pressure, and needs to be calculated as
pressure varies spatially and temporally
The equations and correlations necessary for determining gas properties are:
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Oil properties Oil properties are density, compressibility, formation volume factor, viscosity and
solubility of gas in oil.
A recent review of the available correlations has been provided by McCain (1991).
of several of these properties. shows the qualitative variationThe following figure
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Reservoir Rock/Fluid I Reservoir fluid flow is governed by complex interactions between
the fluids and the reservoir rock. These interactions become more complicated when, as is
often the case, two or more fluids are present in the same pore.
To appropriately describe the simultaneous flow of two or more fluids in a porous medium
requires a good understanding of both the fluid-fluid and rock-fluid interactions.
3-3 Wettability
When two immiscible fluids co-exist in the same pore space, one preferentially adheres to
the rock surface.
This phenomenon is known as wetting, and the fluid that is preferentially attracted
is referred to as having a higher wettability index.
The parameter which determines the wettability index is called adhesion tension,
and it is directly related to interfacial tension.
Interfacial tension is a measure of the surface energy per unit area of the interface
between two immiscible fluids.
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Examples of such interfaces include the junction between water and crude oil and
the junction between oil and gas.
At least three tests are commonly used to measure rock wettability:
1. Amott test: wettability is determined by the amount of oil or water imbibed in a core
sample compared to the same values when flooded. Amott wettability values range from +1
for complete water wetting to -1 for complete oil wetting.
2. U.S.Bureau of Mines test: wettability index W is the logarithm of the ratio of the areas
under Pc curves in both imbibitions and drainage processes. This index can range between -
1.5 and +1
3. Contact angle test: can be measured directly on polished surfaces. Ranges are from 0 to
75º for water wet, from 105 to 180º for oil wet, and from 75 to 105º for intermediate
wettability.
As a means of estimating wettability, none of these tests is entirely satisfactory:
. The Amott index and the W index can be taken in actual permeable medium, but their
correspondence to capillary pressure is not direct. But both of these methods are measures
of aggregate rather than local wettability.
. The contact angle method is direct but it is not clear to what extent a polished surface
represents the internal surface of the permeable medium.
Most sandstone reservoirs tend to be water wet or intermediate wet, where as most
carbonate reservoirs tend to be intermediate wet or oil wet as illustrated in the following
table.
Wettability class Water wet Intermediate wet Oil wet
No. of Sandstone reservoirs 25 12 23
No. of Carbonate reservoirs 4 18 28
Total 29 30 51
e permeabilityRelativ4 -3
Although relative permeability is not a fundamental property of fluid dynamics, it is
the accepted quantitative parameter used in reservoir engineering.
Relative permeability appears prominently in the flow equations used in reservoir
simulation.
The following figure depicts relative permeability as a function of water saturation
for a two-phase system.
We therefore refer to it as two-phase relative permeability.
If a third phase is present, then each fluid has its own relative permeability, which
differs from the corresponding two-phase relative permeability
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Relative permeability curves and their associated parameters are the most relevant
petrophysical relation for EOR. Darcy's law may be integrated over a finite distance Δx to
give
Vj = - λj ΔΦj/Δx
Where:
λj is the mobility of phase j.
This mobility is the constant of proportionality between the flux of Vj and the potential
difference ΔΦj = Δ (Pj-ρjgD). Mobility can be decomposed into a rock property, the
absolute permeability, a fluid property, the viscosity, and the rock-fluid property, the
relative permeability
λj = K (Krj/μj)
The relative permeability is a strong function of the fluid saturation of phase Sj. Relative
mobility can be defined as
λrj = Krj/μj
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and the phase permeability
Kj = K Krj
Kj is a tensorial property in three dimensions.
The total relative mobility, λrt, is the summation of the phases mobility's and is a measure
of the resistance of the medium to multi-phase flow. Plots of λrt versus saturation
frequently show a minimum, meaning it is more difficult to flow multiple phases through a
medium than any one of the phases alone.
If the relative permeability of a phase is zero, it can no longer to flow, and the saturation at
this point cannot be lowered any further. Reducing the "trapped" oil saturation is one of the
most important objectives of EOR. The trapped oil saturation is called the residual oil
saturation.
It is important to distinguish the residual oil saturation from the remaining oil saturation.
The residual oil saturation is the oil remaining behind in a thoroughly water swept region;
the remaining oil saturation is the oil left after a water flood, well-wept or not. The trapped
water saturation is the irreducible water saturation. It is not the connate water saturation,
which is the water saturation in a reservoir before any water is injected.
The end point relative permeability's are the constant relative permeability of a phase at
the other phase's residual saturation. The end points are measures of wettability. The
wetting phase endpoint relative permeability will be smaller than the nonwetting phase
endpoint. Other view the crossover saturation of the relative permeability's as a more
appropriate indicator of wettability.
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No general theoretical expression exists for the relative permeability function. Several
empirical functions for the oil-water curves are available.
Because it requires a three-dimensional representation, three-phase relative
permeability is often shown on ternary diagrams, with isomer’s displayed at various
saturation combinations.
Leverett and Lewis (1941) were one of the first to use this representation.
The following figure shows a typical relative permeability curve for a three-phase
oil/gas/water system.
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Successful simulation of a multiphase system hinges on adequate relative permeability
information.
Since relative permeability is a function of saturation, which varies over a reservoir’s life,
the best way to get adequate information is to incorporate relative permeability models
into the reservoir simulator.
Several models are available (Honapour, et al. 1986), each claiming varying degrees of
merit. The simulation engineer must determine which model is appropriate.
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Capillary pressure5 -3
The water in the capillary tube rises above the water level in a container to a height
that depends on the capillary size. Although strictly speaking, the water still finds its
level, it does so in such a way as to maintain an overall minimum surface energy.
In this situation, the adhesion force allows water to rise up in the capillary tube
while gravity opposes it. The water rises until there is a balance between these two
opposing forces. The differential force between adhesion and gravity is the capillary
force.
Capillary pressure is important in porous media flow description because of the
saturation distribution in the capillary-like pore spaces. The following figure shows
the drainage and imbibitions in the porous medium.
Capillary pressure is the most basic rock-fluid characteristic in multiphase flow. If the
phases and the interface are not flowing, a higher pressure is required in the nonwetting
phase than in the wetting phase to keep the interface from moving. A static force balance
across the interface yields:
P2 – P1 = 2 δ cosθ / R = Pc = Capillary Pressure
If either the interfacial tension is zero or the interface is perpendicular to the tube wall, the
capillary pressure is zero.
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Actual capillary pressure curves exhibit a sense of hystersis, which can tell us much about
the permeable medium.
Leverett proposed a nondimensional form of the drainage capillary pressure curve that
should be independent of the pore size:
J (Snw) = Pc√k/φ / δcosθ
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Residual Phase Saturation6 -3
The mechanism for residual phase saturation may be illustrated through two simplified
models:
1. The pore doublet model
This model assumes well-developed Poiseuille flow occurs in each path of the doublet and
the presence of the interface does not affect flow. When the wetting-nonwetting interface
reaches the outflow end of the doublet in either path, it traps the residual fluid. The
interface of the large-radius path will reach the outflow end before the small radius path,
and the nonwetting phase will be trapped in the small-radius path.
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This model illustrates several qualitative observations about phase trapping:
a. The nonwetting phase is trapped in large pores; the wetting phase, in small cracks and
crevices.
b. Lowering capillary forces will cause a decrease in trapping.
c. There must be some local heterogeneity to cause trapping.
2. Snap-off Model
The snap-off model assumes a single-flow path of variable cross-sectional area through
which is flowing a nonwetting phase. For certain values of the potential gradient and pore
geometry, the potential gradient in wetting phase across the path segment can be less than
the capillary pressure gradient across the same segment. The external force is now
insufficient to compel the nonwetting to enter the next pore constriction. The nonwetting
phase then snaps off into globules that are localized in the pore bodies of the flow path. The
condition for reinitializing the flow of any trapped globule is
ΔΦw + ΔρgΔL sinά >= ΔPc
Where:
ΔL is the globule size and ά is the angle between the globule's major axis and the horizontal
axis.
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Capillary Desaturation Curve (CDC)7 -3
Typically these curves are plots of percent residual (nonflowing) saturation for the
nonetting or wetting phases on the y axis versus a capillary number on a logarithmic x axis.
The capillary number Nc is a dimensionless ratio of viscous to capillary forces and can be
written as:
Nc = Vμ/δcosθ or Nc = kΔP/ δcosθ
= φ/C (jcosθa - cosθr/√2ζ) ²
Procedure for CDC Estimation:
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1. Pick a point on the IR curve corresponding to the maximum initial nonwetting
saturation. This point is the nonwetting saturation corresponding to what would be trapped
if the displacement were to take place at zero capillary number, that is, spontaneous
imbibitions of only the wetting phase.
2. Pick another point on the IR curve at lower nonwetting saturation. The trapped
nonwetting saturation is the difference between the nonwetting saturation here and in step
1. The capillary pressure in the globules just mobilized corresponds to a point on the j-
function curve where the nonwetting saturation on this curve is equal to the nonwetting
saturation on the IR curve.
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3. Insert the j-value from this procedure into capillary number equation to obtain the Nc
corresponding to the residual nonwetting phase saturation. The tortuosity, ζ, may be
obtained from the medium's formation resistivity factor, the constant C is equal to 20 a
suggested, and the advancing, θa, and receding, θr, angles come from the correlation of
Morrow.
These steps generate one point on the nonwetting phase CDC curve.
4. Repeat step 2 with another nonwetting phase saturation to generate a continuous curve.
The procedure reinforces the following points about the CDC curve:
a. The capillary number Nc defined previously is the most general definition.
b. Increasing Nc will cause the irreducible nonwetting phase saturation to decrease.
c. The local heterogeneity is present through the pore size distribution dependence of the j-
function and IR curve.
d. The entire procedure is passed on a specific distribution in the pores, which is determined
by the wettability.
32
33
34
35
36
37
38
Chapter 4
Non-thermal Recovery Methods
Non-thermal heavy oil recovery methods could be considered for moderately viscous
oils (50-200cp), thin formation(less than 9 m), low permeability's(less than 1 Darcy)
and large depths (greater than 900m). Non-thermal methods serve to reduce the
viscosity of the oil, increase the viscosity of the displacing fluid, or reduce the
interfacial tension.
Polymer Flooding
In this process, a water-soluble polymer is used to decrease the mobility ratio of
water flooded by increasing the drive water viscosity, and primarily improve the
volumetric sweep efficiency. It is applicable in the less than 10 to 150 cp viscosity
range. Laboratory and simulation studies showed that the oil recovery is generally
higher than water flood oil recovery, perhaps 1 to 5 incremental. Polymer flooding
was reported to be successful in Huntington Beach, California and in Taber South,
Canada. This process is not cost-effective for heavy oil.
:fold-The advantages of polymer flooding are two
1. a reduction in the quantity of water required to reduce the oil saturation to its
residual value in the swept portion of the reservoir;
2. an increase in the areal and vertical coverage in the reservoir due to a reduced
water flood mobility ratio.
Mobility Ratio Concept
The mobility ratio is defined as the mobility of the displacing phase to the mobility
of the displaced phase. The water-oil mobility ratio can be written as:
M = λw / λo = Krw μo / Kro μw
39
The role of water-soluble polymers is to increase the water viscosity and also to
reduce the permeability of the rock to water, in other words, to reduce the water-oil
mobility ratio close to unity or less.
After water breakthrough into the producers, the flow of the two phases in the
swept area of the reservoir is controlled by the fractional flow equation:
fw = 1 / ( 1 + (Ko/μo) (Kw/μw) )
and fo = 1 - fw
Method Description
In polymer flooding, a slug of polymer solution is injected into the reservoir with a
prior injection of a low-salinity brine (fresh water) slug. The polymer slug is
followed by another fresh water slug and by continuous water injection. Polymer
flooding improves oil recovery over water flooding by increasing the reservoir
volume contacted. It is successful when applied in the early stages of a water flood
process. Reservoirs with high permeability variations, the risk factor is high.
40
Polymer Types
There are two principle types of polymers being used in field applications:
: is obtained by the polymerization of the acrylamide monomer. It Polyacrylamides
has a molecular weight higher than 3 million and a linear chain molecular structure.
It is sensitive to salt, less expensive and providing higher residual resistance to drive
water injection.
: is obtained from sugar in a fermentation process caused by the Polysaccharides
bacterium Xanthomonas campestris. It is not affected by salinity, and shear effects
can be tolerated. This biopolymer is expensive; its stability degrades at
temperatures above 200ºF, and is not retained on rock surfaces.
Resistance Factor
The measure of the mobility reduction is known as the resistance factor:
R = λw/λp = Krw μp / Krp μw = Mw-o / Mp-o
Polymers with high resistance factors can be used in permeability modification.
Residual Resistance Factor
The measure of the reduction of rock's permeability to water after polymer flow is
known as residual resistance factor
Rr = ( Krw/μw) before polymer flow / ( Krw/μw) after polymer flow
The original permeability of the core, having been reduced by adsorption on the
rock surface and by mechanical entrapment of polymer molecules, cannot be
recovered.
41
Field Projects
Parameter No. of Projects Min Max Mean
Depth, ft 87 400 10,800 4005
T, ºF 88 46 229 117
Permeability, md 80 1.5 7400 453
μo , cp 82 .7 435 21.5
Polymer ppm 48 51 600 279
Recovery, %OOIP 20 0 14 3.85
42
Guidelines for Polymer Application
Reservoir characteristics
Depth: a critical factor only when related to reservoir temperature.
Temperature: less than 200ºF assure a stable polymer solution.
Pressure: is not critical if it permits the injection pressure to be less than the
formation parting pressure.
Porosity: must be medium to high (higher than 18%)
Permeability: good between 50 and to 250 md.
Fluid Characteristics
Oil viscosity: up to 200 cp.
Oil saturation: high
Caustic and Emulsion Flooding
Caustic flooding involves the formation of an oil-in-water emulsion in situ, while in
emulsion flooding, the emulsion is prepared at the surface and subsequently injected
into the formation. Both techniques are readily applicable to moderately viscous
oils. The emulsion causes a decrease in water mobility and an improvement in the
volumetric sweep efficiency.
Displacement Mechanisms of Caustic Flooding
1. The alkaline solution increase the capillary number value by reacting with the
organic acids present in some crude oil to form emulsifying soaps, which reduces the
interfacial tension by two or three orders of magnitude.
2. The alkaline agent changes the injection water pH and the rock wettability is
reversed from oil-wet to water-wet. This mechanism is defined as wettability reversal.
3. Even in the water-wet reservoirs the discontinuous, non-wetting residual oil
phase can be changed to a continuous wetting phase if proper conditions are met.
43
The presence of water droplets in the continuous oil-wet phase raises the pressure
gradient of the flow through porous medium.
4. Entrapment of the oil emulsion droplets by small pores, improves the volumetric
sweep efficiency.
Method Description
The process starts with a water preflush injection followed by the injection of
caustic solution slug of about 10 to 30%PV and by continuous injection of derive
water. The injection of a polymer slug behind the caustic solution for mobility
control is desirable if it is cost effective.
44
Screening Criteria
Temperature: less than 200ºF
Permeability: between 50 and 250 md
Oil Viscosity: less than 150 to 200 cp
Salinity: should be low
There are other special aspects to be considered when screening reservoirs for
caustic flooding such as the mineralogy of the reservoir rock, the CO2 content of the
petroleum reservoir, and the crude acid number.
Reservoir with large gas-cap and extensive aquifer should be avoided.
45
Field Trials
Whittier Oil Field, California, United States
Reservoir characteristics
Avg. depth 1500 ft and 2100 ft
Net oil sand thickness 37 ft and 100 ft
Air permeability 495 md and 320 md
Formation dip 25 to 45º south
Oil viscosity 40 cp
Temperature 120ºF
Well spacing 1 and 2 acres per well
Permeability variation 0.66 to 0.74
Project results and comments
Caustic flood produced more oil than could have been from the continuation of
water flood. It is very important to consider carefully the reservoir geometry and
recovery mechanisms
46
Micellar-Polymer Flooding
A surfactant reduces the oil-water interfacial tension and increases the oil
displacement efficiency. Surfactant flooding has been employed mostly in light oil
reservoirs, but could also be considered in the case of moderately viscous oils. The
main disadvantage of this method, as also of other chemical methods, is the
adsorption of the surfactant on the rock matrix, which causes the surfactant slug to
lose its effectiveness at a short distance from the injection well.
47
Principle and characteristics
The micellar solution composition which assures a gradual transition from the
displacement fluid water to the oil displaced, without the presence of an interface, is
as follows:
Surfactant 10 – 15 %
Oil 25 – 70
Water 20 – 60
Co surfactant 1 - 4 (usually alcohol)
Electrolyte 0.01 – 4 (inorganic salts)
The micellar solution operates miscibly with reservoir fluids including oil and water
without phase separation. The micellar solutions are different from emulsions due to
the microscopic size of the discontinuous phase.
The micellar solutions are also referred to in the literature as surfactant slugs,
microemulsions, soluble oils, and low-tension solutions. At sufficiently high
concentrations, surfactant molecules form aggregates called micelles. They are
translucent, homogeneous, and thermodynamically stable.
48
Description of Process
Micellar or micro-emulsion flooding is a fluid injection process wherein a
microemulsion or micellar solution is injected into the formation and is in turn
displaced by a mobility buffer (polymer) solution. The mobility buffer is in turn
displaced by injected water. Mobility control is important to the success of the
process.
The MP flooding process is applied in general after water flooding. When the
reservoir water salinity is too high, direct contact with the micellar solution is
avoided by first injecting low-salinity brine.
49
Design of Process
The design of a micellar or microemulsion for a specific reservoir is basically a trial
and error procedure. Microemulsion can be either oil external or water external
and must be checked for compatibility with the reservoir crude oil and water.
Mobility control must be designed by flooding in reservoir cores.
t Total mobility = λ
= Krw/μw + Kro/λo
The total mobility can be determined from relative permeability curves. The
minimum mobility is chosen as the design mobility for the fluid system upstream of
the micellar or microemulsion slug. The actual mobility of the stabilized oil bank
may be greater than or equal to this minimum mobility. Therefore, the stabilized oil
bank can never have mobility less than this minimum.
50
Pseudo-ternary Diagram
The three major components of micellar solutions which are oil, surfactant, and
water can be represented on a ternary diagram. In the two-phase region one phase
is oil external and the other is water external. In the one-phase region, all
components are miscible and no interfaces are present. The surfactant slug moving
through the reservoir changes its composition by including oil and water in a
miscible displacement. The salinity of the brine influences the phase behavior of the
micellar solutions which in turn directly correlates with the interfacial tension.
51
The M-1 Project, Illinois, USA
The M-1 Project was a commercial-scale project of the Maraflood recovery process
developed by Marathon Oil Company.
Reservoir Characteristics
Robinson sandstone.
Net avg. thickness 27.8 ft
Avg. Depth 950ft.
Avg. porosity 18.9%
Permeability 103 md
Oil viscosity 7 cp
Salinity 16,575 ppm
Dissolved gas derives mechanism.
52
The secondary recovery consisted of gas repressuring and was followed by water
flooding.
The combined primary and secondary recovery averaged 30%.
Project Design
The scope was to demonstrate economic recover of tertiary oil in a mature water
flood project. In the field, 60% of 407 acres of the M-1 Project area was developed
using 2.5 acre five spot patterns. The remaining area was developed with 5 acre
pattern spacing.
The micellar-polymer fluid injection was in the following sequence:
. The 10% PV micellar slug (10% sulfonate, 80%water, 7.5% oil, and 2.5%salt)
. 105% PV polyacrylamide mobility buffer.
. 35%PV of produced water.
Performance Evaluation of the Project
The M-1 Project demonstrated the technical viability to design, implement on a
large scale, conduct, and evaluate the most complex of the EOR methods.
53
Screening Criteria
Sandstone reservoir
Temperature 200ºF or less
Permeability greater than 20 md
Residual oil saturation higher than 20-25%
at the start of the project
Formation water salinity less than 200,000 ppm
Based on an extensive volume of data from currently proposed, completed and
ongoing MP/EOR field tests, the following are considered to be effective in the
process:
1. Residual oil saturation and distribution: determine the amount of MP/EOR target
oil and the high permeability zones.
2. Reservoir confinement: define boundaries and pay continuity.
3. Natural fractures: Unfavorable factor for an Mp/ROR candidate reservoir.
4. Temperature and depth: temperature is a limiting factor.
5. Permeability and heterogeneity: it is important factor.
6. PVT analysis of crude oil: properties of crude oil at reservoir conditions,
especially the viscosity, is related to the design of the MP chemical system.
7. Makeup and residual water composition: this is an important parameter to
define.
8. Relative permeability's: depends on the fluid distribution which is controlled by
wettability. This will affect mobility requirements.
9. Pattern type and size: play an important role.
10. Clay mineralogy and composition: influence the surfactant adsorption.
11. Rock composition: affect the surfactant's electrolyte environment.
12. Volumetric water flood data.
Economics of Process
Micellar/Polymer flooding economics will depend on to a large extent on the
chemical requirements, cost of chemicals, and oil saturation in the reservoir at the
time the flood is initiated.
A method has been reported for determining "optimum" economic slug size.
"Optimum" slug size is defined as that slug size that will maximize the profits.
Maximum profit occurs when:
δRo/δVs = Cs / (So. Po)
Where:
Ro = Oil recovery
54
Vs = Slug volume
Cs = Cost of injected slug
So = Oil saturation before start of the flood
Po = Price of oil
The profit is maximum when the slope of the oil recovery versus slug size curve is
equal to the right hand side of the equation above. The point of tangency of a
straight line having a slope of Cs/SoPo represents the most profitable slug size.
55
Miscible Fluid Displacement
Miscible oil displacement is the displacement of oil by fluids with which it mixes in
all proportions without the presence of an interface, all mixtures remaining single
phase.
Miscible Agents
Propane, LPG mixtures, and low molecular-weight alcohols: subjected to many
limiting factors such as high costs, unfavorable mobility, and low volumetric sweep.
Natural gas, flue gas, nitrogen at high pressure, and enriched hydrocarbon gas: were
found to achieve miscibility with reservoir oil.
Surfactant slugs: technically efficient.
Carbon dioxide: miscible with reservoir fluids.
Phase Behavior
The miscible displacement mechanism is understood when the phase behavior of oil,
water, and EOR fluids is known. A phase is a homogeneous, physically distinct,
mechanically separable portion of a material with a given chemical compositions
and structure. The ternary diagram represents the phase behavior of a three-
component mixture. The pseudoternary diagram represents the phase behavior of a
multicomponent system, such as a hydrocarbon reservoir, by grouping the
components of the reservoir fluids into three pseudocomponents :
. the light component = C1
. the intermediate hydrocarbons = C2-C6
. the heavy hydrocarbons = C7+
The pseudoternary diagram can simultaneously represent
1. Phases.
2. Component concentration in mixture.
3. Overall composition.
4. Relative amount of each phase in the two-phase region.
56
Hydrocarbon-Solvent Miscible Flooding
Residual oil saturation and IFT
The residual oil saturation decreases when the capillary number
Nc = u.μ/δ ( δ is the interfacial tension)
increases, the interfacial tension should be reduced to its lowest value by injecting a
slug of miscible solvent driven by natural gas until miscibility is achieved.
57
First-Contact Miscibility
The solvents mix directly with reservoir oils in all proportions and the mixture
remains single phase.
Multiple-Contact or Dynamic Miscibility
The miscibility is achieved by the mass transfer of components which results from
multiple and repeated contact between the oil and the injection fluid during the flow
through the reservoir.
There are two processes through dynamic miscible displacement can be achieved in
the reservoir:
Condensing gas drive process: takes place when the oil composition lies to the left of
the limiting tie line and the composition of the injected solvent lying to the right of
58
the limiting tie line. The miscibility results from the in situ transfer (condensation)
of intermediate hydrocarbon from the solvent injected into the reservoir oil.
For a given solvent composition there is a minimum pressure called the minimum
miscibility pressure (MMP) above which the dynamic miscibility can be obtained in
a condensing gas drive process.
Vaporizing gas drive process: takes place when the oil composition lies to the right of
the limiting tie line and the composition of the injected solvent lying to the left of the
limiting tie line. The injected solvents used are natural gas at high pressure, flue gas,
nitrogen, and carbon dioxide. The miscibility is attained above the MMP. The
mechanism of multiple-contact miscibility results from the in situ transfer through
vaporization of intermediate hydrocarbons from the reservoir oil into the injected
solvent lean gas at high pressure.
59
Screening Criteria
Oil viscosity 1cp or less (upper limit: 3 to 5cp).
Depth 1500 -2500 ft for condensing gas drive
Deep reservoirs for vaporizing gas drive
Pressure 1500-3000 psi for condensing gas drive
3500-6000 psi for vaporizing gas drive
Direction of flow is important in all types of miscible processes.
Oil saturation at start of the project: greater than 25%.
High-Risk Factor: Extensive fracturing, a gas cap, a strong water drive, or high
permeability contrasts.
60
Carbon Dioxide Flooding
The use of carbon dioxide to increase the recovery of oil has received considerable
attention recently. CO2 is a colorless, inert, and noncombustible gas. Its density
varies with pressure and temperature as does its viscosity and compressibility
factor.
Factors that Make CO2 an EOR Agent
: improves the mobility ratio.Reduction in oil viscosity
: increases the recovery factor.Swelling of crude oil
: CO2 in solution with water forms arbonate and shaley rocksAcid effect on c
carbonic acid which increases the permeability of the carbonate rock.
: CO2 may develop miscibility through multiple contacts.Miscibility effects
61
62
CO2 Miscible Flooding
Dynamic miscibility of CO2 with light and medium gravity crude oils is generated
as a vaporizing gas drive mechanism. CO2 vaporizes or extracts heavier
hydrocarbons from the oil and concentrates them at the displacement front where
miscibility is achieved.
The MMP above which dynamic miscible displacement with CO2 is possible can be
determined from displacement techniques and miscibility experiments:
Gravity-stable experiments: use a vertically sandpacked and oil saturated test
column.
Slim tube experiment: performed in a 40-ft long, 1/4-inch diameter coiled stainless
steel tube sandpacked and saturated with oil at a given pressure and temperature.
Visual cell observations: describe the gradual color change of the single-phase
effluents.
63
Correlations: estimating miscibility pressure has been made since reservoir
temperature, oil composition and characteristics are factors affecting this pressure.
64
CO2 Immiscible Flooding
Immiscible CO2 oil displacement is best suited to medium and heavy oils since the
oil viscosity reduction is greater and more significant. This process involves
alternating injection of CO2 and water until a certain amount of CO2 has been
injected, then water is injected continuously. WAG process characterized by an
improved mobility.
65
Flood Design and Performance Predictions
CO2 flood design and performance predictions differ from reservoir to reservoir
and for different operation strategies.
: is an initial phase of the CO2 miscible flood.rizationReservoir pressu
: are determined in many ways depending on the reservoir CO2 requirements
geometry and displacement direction and on the miscibility conditions and injection
strategy.
t be taken to ensure that the injection pressures are : care musCO2 injection pressure
always below formation parting pressure. The surface CO2 injection pressure is
calculated to assure the required miscibility pressure in the reservoir.
CO2 Sources, Transportation and Operational Problems
The main CO2 sources are:
. Naturally occurring high-pressure gas reservoirs with high-purity CO2.
. CO2 removed from gas processing plants.
. CO2 produced as a by-product.
66
The method of transportation of CO2 from its source to the oil field depends on
whether the CO2 is liquid or gas.
Corrosion, asphaltene deposition, and handling of the produced CO2 are some of
the operational problems in field applications.
67
Chapter 5
Current Thermal Recovery Methods
Steam Injection
Steam injection is thermal method which supplies the heat needed to increase
reservoir temperature and the energy to displace oil. Application of heat to the
reservoir rock and fluids, can aid oil production through oil viscosity reduction,
thermal expansion effects, increase in sweep efficiency, and possible steam
distillation effect. To day steam injection is regarded as a well-established oil
recovery method, which will become increasingly important in the years to come.
The two commonly used forms of steam injection are: steam flooding or steam
derives, and cyclic steam stimulation. Steam derive uses a pattern flood with
injector and producers. In a single well operation, injecting steam and then
producing oil from the same well, steam injection is called cyclic steam injection,
steam soak, or "huff-and-puff".
Steam Flooding
This is a multi-well, pattern derive process. When steam is injected, a steam
saturated zone forms around the injection well, and further beyond there is a zone
containing condensed steam. The temperature in the steam zone is the steam
temperature, declining as one move away from the well. Steam injection rate is an
important factor, since a high rate can cause early steam breakthrough, while a low
rate leads to heat loss. The temperature increase may cause an increase in the
relative permeability to oil. Gravity override of steam becomes important in thick,
permeable sands. The presence of a gas cap would further promote gravity override
of steam. The water zone thickness is an important factor. A thick water zone would
68
act as a heat sink, while thin water sand may heat the overlying oil. In a typical
steam flood, at the start of production, the water cut decreases and the oil cut
increases. Recovery factor is often lower than 50 %.
Heat Losses
69
70
Cyclic Steam Stimulation
Cyclic steam injection is a single well process and involves the injection of steam for
several weeks (2 to 6 weeks) at the highest possible rates, often above fractures
pressures in order to minimize heat losses. The well is then shut-in for several days
(3 to 6 days) to allow the steam to condense. Following the soaking phase, the well is
put under production. The efficiency of the shut-in or "soak" period duration is
questionable. A long soaking period results in a loss of production, while a short
period prevents adequate steam condensation.
71
Cycling steam stimulation is one oil recovery method which is known to be effective
in recovering oil from heavy oil reservoirs. The field use of this technique dates
back to 1958, when Shell Oil Company steamed a well of the Yorba Linda oilfield of
California. Cyclic steam stimulation process is widely used in Canada and
Venezuela because of its applicability in very viscous oil formations, and quick
payout. The total oil recovery by steam stimulation averages about 10 to 15% of the
oil-in-place. In Cold Lake, Alberta, it is over 25% or higher. In Venezuela, cycling
steaming is a well established procedure for recovering heavy oil and recoveries
from this process as high as 40% have been noted.
The injected heat causes an increase in the reservoir temperature, leading to a sharp
reduction in the oil viscosity and consequently increasing the oil mobility. A
common practice is to inject the steam near the base of the pay zone, because of the
tendency of the steam to migrate to the upper parts of the formation. In very
viscous oil formations such as those of Cold Lake, steam must be injected at fracture
pressures, since the injectivity is very low. Interrwell communication determines
the oil to flow under the influence of the gravitational effect. This is very efficient
mechanism results in high recoveries. A gas cap usually has been adverse effect on
cyclic steam stimulation.
72
Design Criteria
Typical design criteria for finding out whether an oil reservoir is a good candidate
for steam injection were established. Formation depth may be above 200-400 ft (200
ft in Charco Redondo, Texas) to avoid parting pressure of adjacent formations and
should be limited to 5000 ft ( Brea, California) due to heat loss. Higher limit
possible using downhole generators. To minimize heat loss, formation thickness
should be not less than 30 ft (Slocum, Texas). Formation permeability should be
high (between 250 and 1000 md) and porosity should be higher than 18 to 20 %(
Shiells, California). The oil gravity should be in the 12-25 API range with viscosity
about 2000 cp at reservoir temperature. The upper limit can be decreased to 4000
cp or less by cyclic steam injection. Steam injection is applied also to light oils (Brea,
California, with 24ºAPI and 6 cp and El Dorado, Kansas, with 37º API and 4 cp).
Oil saturation at the start of steam injection project should be higher than 40 to
50%.
Steam flood is not successful after waterflood. It is important to have high enough
reservoir pressure to cause rapid movement of oil into the wellbore. The quantity of
steam to be injected is a difficult parameter to decide about. The injection should be
as rapid as possible. Shallow and dip oil reservoirs, thick pay zones with very good
permeability, cheap and high quality water source are some favoring factors to
steam injection, while strong nonuniformity, highly water-sensitive clay content, and
low interwell communication are adverse factors.
The main properties of some Tar sand reservoirs in USA, Canada, and Venezuela
tested by steam injection are given in Table 3.
Table 3 Properties of Tar Reservoirs at locations tested by steam injection
Steam Drive Steam Soak
Depth, ft 935 – 3800 269 – 2500
Net Thickness, ft 110 – 210 52 -110
Gravity, ºAPI 5 – 9.3 - 2 - 9
Reservoir Temperature, ºF 52 – 140 55 – 110
Oil Viscosity, cp 2,159 – 1.6 Million 25,000 – 20 Million
73
Case Histories: Field Development and Results
Characteristics and results of steam injection are presented through four examples
of field application). The experience gained from the Kern River Foam Pilots in
California, USA, shows that steam foam retards steam override and increases
vertical sweep, the infill drilling is necessary to improve the injection-production
balance, and cyclic steam injection is still used to clean old wellbore wells.
The results of the "200"sand, Midway Sunset steam flood in California, USA
showed that limited-entry perforations in a heterogeneous formation with high-
permeability stringers can cause severe channeling when the steam injection rates
are high. The steam generated at 420ºF with 80% quality entered the formation at
350ºF sand-face temperature and 72%quality. The oil production was very sensitive
to the back pressure on the formation. The "200" Sand Midway Sunset project
demonstrated that shallow heavy oil reservoirs with poor cyclic steam performances
could be developed by steam flooding.
The experience gained from the Pikes Peak oil reservoir steam flood in Canada can
be considered interesting and useful results because steam flood has proved to be
successful when applied to reservoirs with high initial oil viscosity (25,000 cp at
reservoir temperature) if the reservoir is preheated through cyclic steam injection
and interwell communication encouraged by small well spacing is achieved. Also,
the results of this project indicates that steam entrains the oil rather than forming
an oil bank and the use of foam-surfactant injection have to be improved to recover
more of the remaining bottom oil.
In order to produce oil from tar sands through wells, a large amount of heat is
needed to reduce the bitumen's viscosity. The heat carrier is introduced through the
well into the reservoir by cyclic steam injection or steam derive. More than 50 steam
injection field tests have been conducted in tar sand reservoirs worldwide and have
demonstrated that steam is an important heat carrier agent in the development of
bitumen resources.
The new approaches to tar sand oil recovery involve horizontal wells, using steam
plus additives such as surfactant, and combination of mining and petroleum drilling
methods. Downhole steam generator equipment developed for tar sand reservoirs
would also be useful.
74
In Situ Combustion
This is a pattern flood process. A small portion of the oil in place is burned
establishing heat to the rock and its fluids. A burning front and combustion zone is
propagated to the producing well by air injection into a well (forward combustion).
In the reverse combustion process, a burning zone is propagated from oil producing
well to an air injection well. This process was developed as a method for recovering
extremely heavy crude oils and has been unsuccessful in the field. More heat is
recovered if water is injected with air (wet combustion). Wet combustion is a
modified form of forward combustion. A modification of the basic process is oxygen
fire flooding which involves injecting oxygen or oxygen enriched gas into the
reservoir. The oxygen floods conducted so far have either failed, or have performed
no better than conventional fire floods.
In situ combustion process is applicable for a wide range of oil gravities (8 to
36ºAPI), but commercial success has been possible only in oils that are sufficiently
mobile at reservoir conditions. Oil viscosity should be less than 5000 cp. Forward
combustion is theoretically the most efficient process. The in situ combustion
process has been successfully applied to a variety of reservoirs having depth,
between 169 ft (Suplacu de Barcau, Romania) and 11,400 ft (West Heidelberg,
Mississippi, USA). The average thickness between 4 ft (Gloriana,Texas) and 120 ft
(Brea Olinda, California). Reservoirs rock porosities are between 16 and 37% and
permeability's are between 40 and 8000 md. Oil saturation at the start of a project
should be higher than 30%. In situ combustion may be applied after water floods.
Comparison of Thermal Heavy Oil Recovery Methods and
Operational Problems
The choice of recovery technique to use in particular reservoir depends on reservoir
characteristics, geology and the drive mechanism. More than one recovery process
may be used. Steam flooding is characterized by a longer payout time and greater
oil recovery than steam stimulation. For thick reservoirs steam is cheaper than air.
Steam injection methods are more economical than combustion. Currently, 60% of
all oils produced by improved recovery methods are by steam injection.
75
A wide variety of operational problems can occur in thermal recovery processes.
The use of any of the heavy oil thermal recovery methods may cause casing and
tubing damage, sand production, corrosion of equipment, and production of
emulsion. High gas production rates, downhole explosion and well bore plugging
with coke may occur in the process of in situ combustion.
Pilot Design and Operation
Pilots play an important role in improving heavy oil recovery, improving developed
technology such as adding chemical to cyclic steam stimulation, and developing a
new technology such as fracturing tar sand reservoirs. They are expensive, but
necessary. Pilots are in fact research projects run in the oil field. The engineer
designing a pilot and his management need good under standing of what probably
can and can not be accomplished considering the heterogeneity encountered in
heavy oil reservoirs. Balancing pilot benefit versus cost is of constant concern to the
pilot manager. Small patterns are preferential because pilot can be completed in less
time. It is important to have frequent decision points where data obtained are
reviewed and changes in pilot design considered. Managers, engineers, operators
need to be both experienced in oil field operations but also looking for ways to
improve the process under test.
76
Chapter 6
Bio-Chemical Recovery Methods
During the last ten years scientific and engineering efforts in the laboratories of
King Saud University (Saudi Arabia) and Cairo University (Egypt) has established
the basic start for Microbial Enhanced Oil Research technology in the Arab World.
It is expected that Microbial Enhanced Oil Recovery (MEOR) may recover up to
30% of the residual oil under the Arab reservoir conditions. The actual recovery,
however can only be determined through laboratory and pilot tests under field
conditions. A new technology should be developed to apply MEOR successfully.
Microbial enhanced oil recovery (MEOR) technology is the process of introducing
or stimulating viable microorganisms in an oil reservoir for the purpose of
enhancing oil recovery. Although several attempts have been made to describe the
MEOR process, no experimental or theoretical model has yet fully incorporated all
of the factors that strongly affect the mechanisms of oil displacement, growth and
transport of bacteria in porous media.
Some microorganisms produce gases that could improve oil recovery. Some other
species produce acids that can improve permeability of the reservoir rocks thus
improve recovery. Microorganisms produce bio-surfactant can decrease surface,
and interfacial tension between oil and water, which causes emulsification. Several
research studies in our Laboratory have shown, that MEOR is a potentially effective
technology for increasing oil recovery through the improvements in interfacial
forces, wettability characteristics, displacement tests and modeling of the process.
There are different forms of microbial oil recovery: Cyclic well stimulation
treatments, microbial enhanced water flooding, permeability modifications, and
wellbore cleanup. In cyclic microbial well stimulation treatments, improvements in
heavy oil production can result from removal of asphaltic deposits from the near-
wellbore region or from mobilization of residual oil in the limited volume of the
reservoir that is treated. Microbial well stimulation process can be considered
successful not only by improving oil production rate but also decreasing the cost of
maintenance and operation of a well. For a microbial enhanced water flooding, It is
important that bacteria be capable of moving through the reservoir and producing
chemical products to mobilize oil. It has been suggested that some bacteria
producing polymers could be used in situ to plug high-permeability zones.
77
Mechanisms
Many species of bacteria produce carbon dioxide and other gases, such as nitrogen
(N2) hydrogen (H2) and methane (CH4), that can improved oil recovery by
increasing pressure and by reducing the crude oil viscosity leading to an
improvement in mobility ratio.
Because many types of microorganisms produce polymers, these microorganisms
have been used to plug high-permeability zones in petroleum saturated sandstones
to improve sweep efficiency and displace bypassed oil. However, these
microorganisms have been shown to reduce rock permeability. The work in the
Netherlands was a selective plugging experiment using Betacoccus extraneous and a
significant increase in oil production has been reported. Recently, the research in
China reported novel microorganisms that produce polymer; Researchers at the
University of Calgary reported a methodology for using ultra micro-bacteria to plug
the formation. Evaporation of volatile hydrocarbons and destruction of paraffin
compounds by microorganisms led to high in polynuclear aromatic compounds that
degrade asphalted material.
Microorganisms produce bio-surfactant that can decrease in surface and oil-water
interfacial tensions to as low as 5 x 10-3 dyne / cm, leading to emulsification. Several
types of microorganisms that produce bio-surfactants have been separated. . Recent
studies in our laboratories at Cairo University reported some species of bacteria
producing polymers and bio-surfactant that can be used in field applications of
MEOR processes.
Microbes also produce low-molecular acids, primarily of low-molecular weight fatty
acids, that can improve permeability in limestone and sandstone rocks with
carbonaceous cementation, and thus improve oil recovery. A potentially useful
group of microorganisms produces alcohols and ketenes. These compounds are
typical co-surfactants that are used in microemulsion solutions for stabilization and
lowering of the interfacial tension promoting emulsification.
Role of Microorganisms on Interfacial Forces, Phase Variation and Rock Wettability Our recent studies at Cairo University were performed to investigate the effect of
biochemical’s from microorganisms, originally present in the crude oils, on the
interfacial forces, phase variation of oleic/aqueous systems and rock wettability. In
78
some of these studies, it was found that interfacial and surface tension was
markedly affected by nutrient type and concentration. This effect depends on the
temperature at which the tests were carried out. In another studies, two Egyptian
crude’s were used, one of them contained bacteria of Clostridium type and the other
contained Bacillus type. The investigators found that, for each crude oil, the phase
variation and interfacial tension was affected not only by the bacterial nutrient type
and concentration but also by salinity, temperature and time of contact between the
crude oil and the nutrient used. This effect depends on the type of crude oil used.
The effect of microorganisms on the rock wettability was investigated and it was
found that bacteria obtained from the crude oil (Safaniyah oil field-Saudi Arabia)
had an effect on contact angles at both 23 and 500C. This effect depends on the type
of nutrient used, type of rock sample, type of microorganisms and temperature of
which the experiments were carried out. During the growth of bacteria, nutrients
are consumed and several metabolites such as gases, acids, alcohols, surfactants,
polymers, etc. are produced. The type of metabolite depends on the type of bacteria
and nutrient used. Therefore, this well affects the rock wettability characteristics. A
better understanding of the mechanisms of wettability alteration is necessary for
79
selecting appropriate bacterial strains, thus designing optimal operational
procedures.
Effects of Nutrient Type, Bacterial Type, Permeability, API and Salinity on MEOR
Twelve, bacterial strains exist in some crude oils and formation waters were
separated and classified. The effect of nutrient bacterial type, permeability, salinity
and API gravity on recovery efficiency of the MEOR process were investigated.
80
Some types of the separated bacterial strains produced gases and surfactants, while
some other strains when cultured in sucrose media produced polymers. It was found
that the most attractive performance, among different types of nutrients (such as
molasses, glucose and sucrose) is the use of commercial molasses. It gives the highest
oil recovery and the large oil-water bank. The variation of pressure during the
floods was observed, which indicate the type of microorganisms that produce more
gases. Also, it was found that the change in sandpack permeability or API gravity of
the crude oil have no effect on oil recovery. A little variation in oil recovery was
obtained by increasing water salinity from 4.2 to l0%. A study on the microbial
characteristics and metabolic activity of bacteria for improved oil recovery in the
Arabic area was presented by Sayyouh. Results of some laboratory and theoretical
studies of MEOR were discussed. These results indicated that some strains of
bacteria were found to produce biogas, biosurfactants and biopolymers, which
improved recovery efficiency during the MEOR process. It was concluded that
although the application of MEOR may be limited due to the high formation salinity
of the Arabian area, new biotechnology may solve this problem. A recent study at
Cairo University showed that presence of 1% molasses concentration increases th
relative permeability to oil. This effect depond on the crude oil type and the
formation water salinity. The results were discussed in the light of system phase
variation, interfacial forces, wettability characteristics, hydrogen ion
concentrations, viscosity effects, and mechanical and mineralogical analysis of the
cores.
81
82
Possible Application of MEOR to the Arab Oil Fields
Based on the analysis of data obtained from more than 300 formations in seven
Arab counties, (Saudi Arabia, Egypt, Kuwait, Qatar, UAE, Iraq and Syria), the
possibility of the application of MEOR to the Arabian area was investigated. The
basic parameters studied include formation permeability, reservoir pressure and
83
temperature, crude oil viscosity and API gravity, formation connate water
saturation and its salinity.
It was found that some of the Saudi, Iraqi and Egyptian oil fields can be very good
candidates for MEOR processes. Also, depleted oil fields in Egypt and Syria can be
activated by injection of microorganisms, which can be beneficial in producing more
oil. Recently a state of the art of the MEOR process was presented at the 6th
international conference of MPM held in Cairo University. It was concluded that
more extensive laboratory and field research should be carried out in order to
develop a technology in the area of MEOR under reservoir conditions.
Screening Criteria
The data of the Middle East oil fields provide the characteristics of oil reservoirs
that can be used for MEOR field projects. Extensive research is going on today in
order to develop a new technology in the area of bio-technological processes that can
be used under reservoir conditions of temperature, pressure, rock permeability and
water salinity.
No MEOR field projects have been reported where pressures and temperatures
were too high for microbial growth. The usual biological limitation for temperature
is about 170oF and the pressure limitation is about 20,000 psi. Oil reservoirs
temperature and pressure range from 140 to 240oF and from 2000 to 5500 psia,
respectively, which means that MEOR processes can be applied with the
temperature and pressure constraints. Currently, our research studies indicated
that some species of bacteria can resist high temperature effects. These results
obtained have not reported before. The formation rock permeability in most oil
reservoirs ranges from 100 to 3000 md which is a wide range for MEOR
application. A study on the screening criteria for enhanced recovery of some
Arabian crude oils was presented recently. Enhanced recovery methods investigated
in that study included thermal and non-thermal processes.
Environmental Effects of MEOR
The environmental control of MEOR is of great importance. It is necessary to
prevent any adverse effects on the environment when applying this recovery
method. Great effort is being expanded by investigators to understand the complex
subsurface environment of a petroleum reservoir in relation to bacterial
metabolism. One of the possible effects is the stimulation of indigenous sulfate-
84
reducing bacteria which causes bio-corrosion in oil fields. The effect of
microorganisms, used in MEOR laboratory tests, on the corrosion of surface and
subsurface equipment in oil fields was investigated recently. Resulting photographs
by binocular microscope show that corrosion may occur under the bacterial growth.
This was a function of the bacterial type used. It was found also, that some species of
bacteria cause minimum corrosion. Therefore, it was recommended to use certain
types of bacteria for MEOR process that their bio product maximize oil recovery
and minimize biocorrosion.
The possible contaminations of surface, ground water and agriculture land during
bacterial transport are of major environmental concern associated with MEOR field
application.
Sometimes the mineral content of the initial water in the oil formation may inhibit
the growth of the selected bacteria. Injected and connate water salinities equal or
less than 100,000 ppm is required for the application of the MEOR process. Some
types of microorganisms, however, can live in higher salinity environment, although
great efforts will be needed to identify such organisms that resist high salinity
conditions.
The environmental parameters of the reservoir will limit the types of
microorganisms which can be used for the in situ processes. These parameters
include permeability, temperature, pressure, salinity, salt composition, pH, the
nature of the residual oil and nutrient limitation. A new technology is being
considered in the search for ways to apply bacteria to oil recovery. Great effort is
being expanded by microbiologists to understand the complex subsurface
environment of a petroleum reservoir in relation to bacterial metabolism. This may
indicate the lack of experience in this new area of enhanced oil recovery.
85
Chapter 7 North Ward Estes Field-Case History
To illustrate the importance and value of the effective presentation of performance analyses (primary plus
secondary) and design of an EOR project, the North Ward Estes field, a mature field located in Ward and
Winkler Counties, Texas, has been considered.
8-1 Introduction
The North Ward Texas Estes (NWE) field, located in Ward and Winkler Counties, Texas (see Figure l), was
discovered in 1929.' Cumulative oil produced is more than 320 million bbl (25% 0OIP). The field has been
waterflooded since 1955.
Geologically, the NWE field resides on the western flank of the Central Basin Platform. Yates, the dominant
producing formation, includes up to seven major reservoirs and is composed of very fine-grained sandstones to
siltstones separated by dense dolomite beds. Within the 3,840-acre project area, average depth is 2,600 ft.
Porosity and permeability average 16% PV and 37 MD, respectively. Reservoir temperature is 83°F. The flood
patterns are 20-acre, five-spots, and line drives.
CO2 flooding was implemented in early 1989 in a six-section project area located in the better part of the field
in terms of cumulative oil production and reservoir rock quality.
FIELD HISTORY AND DEVELOPMENT
Except for the most productive parts, which were drilled on 10-acre spacing, the field was initially developed on
20-acre spacing.
Until the early 1950s, a typical completion consisted of drilling to the top of the Yates, drilling ahead and
checking for gas caps, setting casing through the gas sands, drilling to total depth, shooting the producing
section with nitroglycerine, cleaning out the hole, and hanging a perforated liner from the casing. Practices
changed in the early 1950s to casedhole completions, hydraulic fracturing, and acidizing. About one-half of the
current injectors are shot, open-hole completions. Vertical sweep has been adversely affected because of the
inability to measure and control the injection profiles.
Figure 2 shows the production and injection history of the project area. Primary production peaked in 1944
and was approaching the economic limit in the mid-1950s. A 960-acre pilot waterflood began in 1954. Oil
production responded quickly, and the flood was expanded to the rest of the project area during the next two
years. The prevailing flood patterns were 40-acre, five-spots.
Oil production increased steadily after 1954, reached a peak in 1960, and then declined at 11%/yr until
1979, when it began to stabilize as a result of drilling infill and replacement wells, injection-profile modifications
by means of polymer treatments, and pattern tightening and realignment (Section 3 and 6 through 8 were
converted to 20-acre, five spot patterns and Section 9 and 10 to 20-acre, line drive patterns).
successful, as evidenced by the 2.3 ratio of ultimate secondary to ultimate primary production from wells
existing at the beginning of waterflooding. The favorable mobility ratio in these reservoirs indicates good areal
sweep efficiency. Because of the high Dykstra-Parsons coefficient (0.85) and permeability contrast among the
major sands, the vertical conformance has been poor. Even after injection of 2.6 waterflood-moveables PV, less
than 50% of the oil recoverable by waterflooding has been produced.
86
RESERVOIR GEOLOGY AND PROPERTIES A comprehensive geologic study and reservoir characterization was conducted to characterize the individual
reservoirs of the Yates, which consist of very fine-grained sandstones to siltstones separated by dense
dolomite beds. In descending order, these sands are Sands BC, D, E, Strays, J1, and J2 (see Figure 3). The
general depositional environment was a tidal-flat to-Iagoonal setting situated to the east of and behind the
shelf margin. The reservoirs were deposited as sand and silt in the subtidal-to-beach environment and siIt-
to-clay in the supratidal environment. Depositional strike was parallel to the shelf margin, which is parallel
to the present northwest/southeast section lines.
Sand BC is a siltstone to fine-grained sandstone with detrital clay. The depositional environment was
that of a shallow-water tidal flat with an abundant amount of windblown sediments. A zone of low porosity
and permeability trends northwest/southeast through the middle of the project area. Most of Sand BC was
in the original gas cap. Sands D and E are similar to Sand BC, but their porosities and permeability's are
more variable. The Strays sand is composed of "thin-bedded, lenticular, and intertidal to subtidal siltstones
and fine-grained sandstones with the highest clay content of any Yates interval. Because of this,
permeability and reservoir continuity suffer while porosity remains high. Sands J1 and J2 are composed of
coarser sands with much less clay content and, therefore, have higher effective porosities and
permeability's. The depositional environment was a beach to near-shore marine where turbulence
winnowed finer silts and clays out of the strike-oriented sand deposits. Table l lists average reservoir
properties for the Yates.
8-2 LABORATORY WORK
Extensive laboratory work was conducted to support the evaluation of CO2 flooding in the NWE field.
. Black-oil PVT and oil! CO2 phase-behavior studies of recombined separator oil and gas samples (see Table
2) determined oil swelling, viscosity reduction, and phase transition pressure vs. mole percent CO2, The PVT
data show the typical complex phase behavior exhibited by CO2/light-crude-oil- systems at low reservoir
temperature (see Figure 4).
. Slim-tube experiments determined minimum miscibility pressure (MMP). Figure 5 shows the results of
the displacement of reconstituted reservoir fluid by pure CO2 in a packed column at different pressures.
Additional displacement tests were conducted with five different CO2/hydrocarbon-gas mixtures. The
MMP ranged from 1,010 to 1,350 psia vs. 937 psia for pure CO2, No significant changes in ultimate slim-
tube oil recovery were observed. These tests verified that published correlations adequately estimate the
MMP for NWE oil and impure CO2,
. CO2 flooding of restored-state composite cores determined the mobilization and recovery of the waterflood
residual oil saturations, Sorw' The core assembly (see Figure 6) was constructed from l-in.-diameter plugs
drilled from NWE cores epoxied into confining stainless steel sleeves. Capillary contact between segments was
maintained with sieved core material. The displacement tests were preceded by cleaning-the core assembly with
toluene, methanol, and CO2; injecting brine into the evacuated core; displacing the mobile brine with
reconstituted reservoir fluid; and waterflooding to Sorw.
Table 3 lists the residual oil saturations to miscible flooding; Sorm determined at reservoir temperature
and at pressures a few hundred psi above the MMP with pure and impure CO2 and with different water-
alternating-gas (WAG) injection ratios. These values should be obtained in the reservoir if levels of physical
dispersion in the core floods are comparable with those obtained in the field and if only a small part of the
long core was needed to develop multiple-contact miscibility (MCM). No field data are available for NWE;
however, where core flood and field Sorm values have been compared, good agreement has been found. . Amott tests determined the wettability of wettability-preserved cores. The Amott index to oil was zero for all
tests, suggesting that the Yates sands are water-wet.
87
8-3 Simulation Approach
The initial CO2 flood design called for the selection of typical patterns from the project area, a detailed
reservoir characterization of each such pattern, history matches of the waterflood performance, predictions for
continuation of the waterflood, predictions for CO2 flooding, and scale up of the predictions for these typical
patterns to the whole project area.
However, time constraints, computer cost, and concerns about data availability and quality dictated a
change to the simpler approach of average patterns. Three-dimensional-pattern models were developed for
four of the six sections. Ten to twelve layers were necessary to characterize the seven major sand bodies of
the Yates. An areal view of the model and the layer properties for one of the models are shown in Figure 7
and Table 4, respectively. Net pay and porosity for each major sand body are averages developed from
geological maps. The permeability stratification within and among the major sand bodies was developed
from core data and injection profiles. The Dykstra-Parsons coefficient for the layered model agreed with
that calculated from core data.
A finite-difference, four-component, modified black-oil simulator was selected for history matching and
watert100d and CO2 flood predictions. This simulator is suitable for first-contact miscibility or for multi-
contact miscibility if the miscibility occurs within a mixing zone having a length that is small compared with the
length of the imposed grid.
8-4 CO2 INJECTIVITY TEST
A CO2 injectivity test was conducted to investigate injectivity losses during CO2 and water injection cycles.
Potential injectivity loss was a concern because of the sensitivity of project economics to injection rates, an
injector in good mechanical condition and with no hydraulic fracturing was selected for this purpose. Before,
during, and after CO2 injection, step-rate tests, injection-profile surveys (Figure 3), and pressure-transient
falloff tests were run. After injection of 30 MMscf (1.3% HCPV) of CO2, the well was returned to water
injection. The major conclusions were as follows:
. No reduction in injection rates was observed during or after CO2 injection. The CO2 injection rate
(expressed in terms of reservoir barrels) was about 20% higher than the water injection rate at the
same flowing bottom hole injection pressures. . No significant change in injection profile was observed during and after CO2 injection. . The CO2 falloff data were used to estimate such parameters as mobility ratio, swept volume, and
average CO2 saturation in the swept region. These values were in agreement with laboratory
measurements from CO2 core floods.
There is some uncertainty about whether enough CO2 was injected to detect potential losses in injectivity.
Because reductions in injectivity generally are not associated with water-wet systems and because no changes in
injectivity were observed during the core floods (for two of the core floods, a chase-water injection state was
added for measuring injectivity changes), additional expenditures for a prolonged field injectivity test could not
be justified.
HISTORY MATCHING
88
History matching was conducted by entering the scaled oil production and water injection rates for the years
1929 to 1986 and letting the simulator calculate the gas and water production rates and reservoir pressures.
Because of limited COR and pressure data, history matching consisted mostly of matching water production
rates. The matches were obtained largely by adjusting layer permeability's and, to a lesser degree, the oil and
water relative permeability curves (see Figure 8).
To improve the prediction of when CO2 will breakthrough at the producers, particular attention was paid
to matching the water breakthrough time after waterflood initiation. In developing the average pattern models,
most of the oil response and water breakthrough observed in the field between 1955 and 1962 were assumed to
come from high-permeability zones. This assumption apparently is supported by the good correlation between
cumulative oil and cumulative water production for individual wells during 1955-1962 (see Figure 9). Wells with
the highest cumulative water production during this period also had the highest cumulative oil production.
PERFORMANCE PREDICTIONS-PATTERNS
The history matches were followed by prediction runs for continuation of the waterflood and for CO2 flooding.
Figure E-I0 shows the simulation results (history match and waterflood and CO2 flood predictions) for one of
the average patterns. Simulator input parameters specific to the CO2 flood predictions were as follows.
. WAG-Because core floods implied that a WAG ratio of 1:1 was optimal, CO2 flood predictions were run at
that WAG ratio, injecting 2.5% HCPV per WAG cycle. . Injection rate-CO2 injection rates (in terms of reservoir barrels) were increased 20% above the average
water injection rates. The results of the field injectivity test justified this increase. . Slug size-a 38% HCPV CO2 slug was injected over a 10-year period. As discussed below, this slug size was
selected on economic considerations. . Sorm-Predictions were run with 12% PV; the value was determined from CO2 core floods conducted at a
1:1 WAG ratio. No additional water blocking over that already reflected in the experimental Sorm was
introduced. . CO2/Oil Mixing Parameter-a mixing parameter of 0.67 was used in a modified black-oil simulator to
approximate the influence of viscous fingering on sweep efficiency in coarsely gridded simulations.
Sensitivity studies were conducted to examine the effects of changes in WAG ratio, Sorm CO2/oil mixing
parameter, and vertical permeability on oil recovery. Continuous CO2 injection (zero WAG ratio) recovered
only 7.1% OOIP, compared with 9, .8% OOIP with a WAG ratio of 1:1, mostly because of excessive CO2
channeling through high-permeability layers. At a WAG ratio of2:1, peak oil production rates were maintained
for a longer period. Incremental recovery, however, decreased to 7% OOIP because of higher Sorm range (see
Table 3) and variations in the CO2/oil-mixing parameter between 0.5 and 0.75, the incremental oil recovery
ranged from 6.3 to 10.5% OOIP. Changes in vertical permeability from 0 to 10% of horizontal permeability had
a negligible effect on incremental oil recovery. Analytical models also predict that gravity override (the major
source of CO2 flood oil), the distance the solvent will travel from the injector until it is concentrated at the top of
the layer, is greater than the distance between injectors and producers for plausible vertical permeability's.
OPTIMUM ECONOMIC CO2 SLUG SIZE
Oil recovery predictions were made for seven CO2 slug sizes (15 to 75% HCPV). The economically optimum
slug size was found by balancing the increase in revenues from additional oil production with the cost of
purchasing additional CO2 and the increasing capital and operating costs to process larger volumes of produced
CO2, In terms of rate of return, the optimum slug size was found to be between 38 and 60% HCPV of CO2
injected. All predictions were run at a 38% HCPV slug size, requiring a CO2 recycle plant capacity of 65
MMscf/D for the project.
89
8-5 Performance Pridiction
The CO2 flood prediction for the entire project area (see Table E-5) is based on the scale-up of the average
pattern simulation results. The scale up of the four sections for which average pattern simulations were
performed is straightforward. The prediction for a given section equals the prediction from the average pattern
of that section times the number of patterns to be flooded with CO2 (i.e., it is simply the reverse of the scale-
down step that defined the average patterns).
No pattern simulations were performed for Sections 9 and 10 because of their similarities in waterflood
performance with Sections 8 and 7, respectively. Because Section 9 and 10 were converted to line drives in 1979,
correction factors had to be developed before the predictions for five-spot patterns could be applied. These
correction factors were developed as follows. A line drive model was initialized with the history matched
saturations and pressures from one of the averaged five-spot patterns as of 1979 (the year when pattern
realignments and tightening began in the field). The line drive pattern was water-flooded for 10 years (to allow
the saturation and pressure distributions from the five-spot to adjust to those found in a line drive) after which a
CO2 flood prediction was made. Annual correction factors to convert five-spot CO2 flood performance
predictions to those expected from line drives were developed from the CO2 flood prediction for the previously
mentioned line drive and the prediction for the five-spot that was used to initialize the line drive.
90
Fig.1 NEW Field
Fig.2 Production and Injection History, Six-Section Project Area
91
Fig.3 Injection Profile Surveys
Table 1 Yates Reservoir Properties( CO2 Project Area
92
Fig.4 Phase Transition Pressures vs. Mole Percent CO2
Table 2 Analysis of Separator and Reservoir Fluids
93
Fig.5 Percent OOIP Recovered vs. Pressure
94
Fig.6 Long Core Properties
Table 3 CO2 Core Floods
Fig.7 Areal View of 1/8 Five-Spot Pattern
95
Table 4 Layer Properties of an Average Pattern
Fig.8 Water/Oil Relative Permeability
96
Fig.9 Correlation for wells on 10-Acre spacing
97
Fig.10 Reservoir Simulation Results for an Average 1/8 Five-Spot
Table 5 CO2 Flood Performance Prediction
98
Artificial lift in Egypt
The Egyptian fields need some sort of artificial lift in order to restore the production
rate to a good level and to enhance the ultimate recovery. Out of 1290 artificial lift
wells in Egypt about 35% are on beam pumping (most of them in GPC, 240 wells,
70 wells, in Agiba, 35 wells in Petrobel), ESP's are about 34% (most of them in
Petrobel, 171 wells, Khalda, 94 wells), and about 28% are gas lift wells (GUPCO has
265 wells, and SUCO has 26 wells) , and about 3% on hydraulic and jet pumps.
Selection of the suitable artificial lift method is an important aspect to the long-term
profitability. A poor choice may reduce production and increase operating costs.
The design and analysis of any lifting system should have the inflow performance
relationship, which represents the well ability to produce fluids, and the piping and
lifting facilities. There are many factors that affect the selection of the best artificial
lift method such as, energy and operating cost, reservoir characteristics,
environmental and geographic problems, well productivity, reliability, well
conditions and equipment supply. All of these factors must be considered when
selecting the best method.
Major types of artificial lift include: Electric Submersible Pumping system(ESP),
Beam pumping, Gas lift, Hydraulic piston type pumping system, Hydraulic jet
system, plunger lift, and Cavity pumping system. The major companies in Egypt
such as GUPCO and SUCO are using gas lift as a preferable system in offshore
wells. Petrobel is using rod pumping in the land wells and has used the ESP the
offshore fields. GPC and Agiba are using mostly the beam pumping system.
Khalda's Company is using ESP's for high production rates.
99
Chapter 8 RESERVOIR MANAGEMENT
Reservoir management has advanced tremendously during the past 30 years. The techniques and
tools are better, reservoir characterization has improved, and automation using mainframe and
personal computers has helped data processing and management.
The synergism provided by the interaction between geosciences and engineering has been quite
successful, and the reservoir management team concept involving relevant functions is becoming
more popular. Team members are beginning to work more like a "well-coordinated basketball
team" rather than "a relay team."
It is believed that using an integrated approach to reservoir management along with the latest
technological advances will allow companies to extract the maximum economic recovery during the
life of oil or a gas field. It can add years of recovery to the life of a reservoir.
Because production in all fields declines over the years, innovations that prolong cost-effective
recovery should be of global interest.
Importance of Integrative Reservoir Management
The modern reservoir management process involves goal setting, planning, implementing,
monitoring, evaluating, and revising plans. Setting a reservoir management strategy requires
knowledge of the business, political, and environmental climate. Formulating a comprehensive
management plan involves depletion and development strategies, data acquisition and analyses,
geological and numerical model studies, production and reserves forecasts, facilities requirements,
economic optimization, and management approval. Implementing the plan requires management
support, field personnel commitment, and multi disciplinary, integrated teamwork. Success of the
project depends upon careful monitoring/surveillance and thorough, ongoing evaluation of its
performance. If the actual behavior of the project does not agree with the expected performance, the
original plan needs to be revised, and the cycle (implementing, monitoring, and evaluating) should be
reactivated.
It is a well-known fact that reservoir studies are more effective when geoscientists and engineers
work together, and reservoir management plans are more productive if all functional groups are
involved. Thus, it is essential to have an integrated reservoir management approach for maximizing
the economic recovery from a reservoir.
Current challenges and Areas of Future
The current challenge primarily concentrates on the need
(A) for improved definition of reservoir characteristics,
(B) to track the movement of fluids through the reservoir, and
(c) to control that movement.
The problem is not only in our ability to displace oil, but also to contact a major portion of the oil.
This clearly implies that we have to develop technology further in order to improve volumetric sweep
efficiency in the reservoir.
Outlook and the Next
In the years ahead, even more attention will be given to integrated reservoir management.
The areas that will play an increasing role are:
Team Effort
100
Economic recovery from a reservoir can be maximized by an integrated group effort. Decisions
pertaining to a field will not be made by a single person but by a team that will consider the entire
field (i.e., reservoir, wellbores and surface facilities, in addition to economics). A team effort
involving people from various functional areas will become necessary for the development and
implementation of a successful reservoir management program.
Role of Geophysics in Reservoirs Management
Any reservoir model must provide a description of the reservoir that correctly accounts for spatial
variation and continuity of porosity, permeability, and fluid saturations. An integrated geoscience
and engineering model provides information about the likely fluid flow paths and an information
management system for better surveillance and monitoring of a reservoir.
Today, geophysics is beginning to play a key role in reservoir development, production, and EOR
projects. People are beginning to realize the value of geophysics for reservoir description and
monitoring of projects.
Core analyses and well logs provide the detailed data about the immediate vicinity of the well;
however, the question of how to interpolate these data between wells always arises. Reservoir
geophysics (seismic reflection) can provide this information, but it requires closer interaction
between engineers, geologists, and geophysicists.
It is anticipated that geophysicists will be involved throughout the life of a reservoir. During the
initial phase of development t, they will play a key role in identifying key reservoir features and
developing geologic model during secondary and EOR projects, they will help monitor the fluid
movement through the reservoir.
Storing and Retrieval of Data
Storing and retrieval of data during reservoir life cycle poses a major challenge today. The industry
is poised to develop technology to create a seamless flow of geoscience and engineering data from
heterogeneous hardware and database systems. The goal is to provide user access to
multidisciplinary information from a common platform through a common user interface.
Integrated Software
A major breakthrough in reservoir modeling has occurred with the advent of integrated geoscience
and engineering software. However, the challenge is now to affirm the effectiveness of the software
in real life situations utilizing multidisciplinary groups working together.
Starting Too Late
Reservoir management was not started early enough; and when initiated, management became
necessary because of a crisis that occurred, and it required a major problem to be solved. Early
initiation of a coordinated reservoir management program could have provided a better monitoring
and evaluating tool, and it could have cost less in the long run. For example, a few early Drill Stem
Tests (DSTs) could have helped decide if and where to set pipe. Also, performing some early tests
could have indicated the size of the reservoir.
Early definition and evaluation of the reservoir system is a prerequisite to good reservoir
management. The collection and analysis of data play an important role in the evaluation of the
system. Most often, an integrated approach of data collection is not followed, especially immediately
after the discovery of a reservoir. Also, in this endeavor not all functions are generally involved.
Sometimes the reservoir management staff has difficulties in justifying the data collection effort to
management because the need for the data, along with its costs and benefits, are not clearly shown.
Lack of Maintenance
Calhoun draws an analogy between reservoir and health management. 6 According to his concept, it
is not sufficient for the reservoir management team to determine the state of a reservoir's health and
then attempt to improve it. One reason for reservoir management ineffectiveness is that the reservoir
and its attached system's (wells and surface facilities) health (condition) is not maintained from the
start.
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Reservoir Simulation – A Basic Tool of Reservoir Management
(particularly local grid refinement) to partially alleviate grid reservoir models-fineUse of
many of the problems resulting from reservoir heterogeneity, flow channeling, and the non-
existence of scale-up rules can translate laboratory results to field applications.
Simulation of Oil Recovery Methods with Finite Difference Simulators
Reservoir Rock Idealizations
istribution function in each geologic layer.described by a normal d : Single Porosity
: where two distinct types of porosity coexist in a representative rock volume Dual Porosity
such as naturally fractured reservoirs.
it.normal distribution function in each geologic un-: fit a logSingle Permeability
: is the idealization of the reservoir systems where both the matrix and Dual Permeability
fracture network have continuity and transmissivity is not insignificant compared to that of
the fracture.
Reservoir Fluid Classification point is far to the right of the bubble point.: the critical Black Oil
points are fairly close to the critical point.-: BubbleVolatile Oil
: the critical point is to the left of the reservoir dew point.Gas Condensate
sing any liquids. In surface : solely exists as gas in the reservoir without condenWet Gas
separators, liquids are formed.
.: exist as gas in the reservoir and in the surfaceDry Gas
Enhanced Oil Recovery
: are simulated by black oil or compositional production Primary and secondary oil
formulations.
aimed primarily at reducing the waterflood residual oil. :ecoveryEnhanced oil r
The most notable of these processes are steam injection, polymer or alkaline waterflood,
micellar-polymer flood, and miscible gas flood.
hbor Connectionsneig-Window Modeling, Local Mesh Refinement, and Non
It is practice to model a window area of a reservoir using a fine grid system.
102
Boundary conditions of the window area are hard to determine. One solution to this problem
is to use the local mesh refinement in the window area while using coarse grid in the rest of
the field.
Non-neighbor connections are used to connect nodes for two different but adjacent layers on
both sides of a fault.
Infill Drilling and Well Recompletion
ing large amounts of by in San Andres carbonates has resulted in recover Infill drilling
waterflooding.
:Fine gridding
track water-oil interface
evaluate the possible benefits of a perforating recompletion program.
determine the optimal location of infill wells.
Reservoir Simulation as an Aid to Reservoir Description
generally we rely on the development or production geologists to Reservoir heterogeneities:
that can be used to construct a geological modeldescribe the reservoir and build up a
of the reservoir. mathematical model
:Grid Simulation-Fine vs. Coarse
Example:
Inverted five-spot waterflood pattern.
Difference simulators-Accuracy and Reliability of Finite Numerical errors: truncation errors, round off errors, and numerical dispersion.
Coarseness of the grid and time step size could cause errors: future may solve this problem by
super computers.
References
1. Carcoana, A.: Applied Enhanced Oil Recovery, Prentice Hall, Inc., (1992)
2. Farouq Ali, S.M.: Practical Heavy Oil Recovery, Heavy Oil Recovery Technologies Ltd.,
(2001).
3. Archer, J.S. and Wall, C.G.: Petroleum Engineering –Principles and Practice, Graham,
Trotman, (1986).
4. Secondary and Tertiary Recovery Processes, Interstate Oil compact Commission,
Oklahoma, (1974).
103
Edition, ndPrint, 2 KSU(In Arabic), . Sayyouh, M.H.: Improved Oil Recovery Methods, 5
(2004).
6. Sayyouh, M.H.:"Microbial Enhanced Oil Recovery: Research Studies in the Arabic Area
During the Last Ten Years", SPE Paper 75218, This Paper was prepared for presentation
at the SPE/DOE, Oklahoma, USA, ( April, 2002).
8. Sayyouh, M.H.: EOR Manuals (1985-2004).
9. L. Lake: Enhanced Oil Recovery
/scholar.cu.edu.eg/?q=Sayyouh. 10
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