1

Artificial Oil Recovery Enhancement

Methods

Dr.M.Helmy Sayyouh

Professor and Chairman

Petroleum, Mining, and Metallurgical Department

Cairo University

April, 2004

2

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

3

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

4

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

5

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

6

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

7

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.

8

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.

9

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

10

. 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

11

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

12

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

13

.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.

14

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.

15

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

16

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.

17

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:

18

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

19

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.

20

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

21

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

22

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.

23

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.

24

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.

25

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.

26

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

27

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.

28

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.

29

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:

30

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.

31

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.

101

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

104