3 Improved Oil Recovery.pdf

7292019 3 Improved Oil Recoverypdf

httpslidepdfcomreaderfull3-improved-oil-recoverypdf 130

Improved Oil Recovery

The use of reservoir energy to produce oil and gas generally results in a recovery of

less than 50 of the original oil in place The primary recovery mechanisms of

solution gas drive gas cap drive and water drive or a combination of one or more of

these and gravity drainage account for most of the worlds oil production Secondary

recovery techniques in which external energy is added to a reservoir to improve theefficiency of the primary recovery mechanisms have been in use for many years

The injection of water to supplement natural water influx has become an economical

and predictable recovery method and is applied worldwide Less commonly gasinjection has been used to displace oil downdip in attic oil recovery projects or to

maintain gas cap pressure Still both primary and secondary recovery techniques

have only been effective in producing roughly one third of the oil discovered Theremaining two thirds more than 300 billion barrels (47696 times 1010 m3) in the United

States alone is a target for more sophisticated processes Such processesdeveloped to increase recovery from reservoirs considered depleted by primary

mechanisms and secondary methods of water or gas injection were historicallytermed tertiary recovery techniques However because some of these processes

may be applied earlier in the life of a reservoir perhaps even in the first day of production the tertiary term is no longer appropriate here and as a result the

term enhanced oil recovery methods has been introduced as the term to be used forall processes that attempt to alter the physical forces that control the movement of oil within the reservoir

Both conventional water and gas injection and the more unconventional enhanced

oil recovery methods can collectively be termed improved oil recovery methods



Waterflooding and Recovery Efficiency

All improved recovery methods involve the injection of fluids into the reservoir via

one or more wells and the production of oil (and perhaps ultimately the injectedfluid) from one or more other wells The methods differ in the nature of the fluidsused and the physical changes they bring about in the reservoir but water usually

plays a part in helping to displace the oil The amount of oil recovered (and obviouslythe success of the project) is dependent upon the percentage of oil in place that iscontacted and moved by the displacing fluid This concept is represented by the

equation

Np = N EV ED (1)

where EV = EAS EVS

The oil recovered (Np) is the product of the volume of the oil in place (N) the

fraction that is contacted (EV) and the fraction of the oil contacted that is displaced(ED) The volumetric sweep efficiency (EV) given as a fraction is the product of the

areal sweep efficiency (EAS) and the vertical sweep efficiency (EVS) Usually all of these values (except N) increase during the life of an improved recovery projectuntil an economic limit is reached Enhanced recovery methods differ in the manner

in which they attempt to improve either EV or ED We will discuss each factorseparately

VOLUMETRIC SWEEP EFFICIENCY The volumetric sweep efficiency (EV) at a

given point in time is the fraction of the total reservoir volume contacted by theinjected fluid during an improved recovery project It is the composite of the arealsweep efficiency (EAS) and the vertical sweep efficiency (EVS)

When oil is swept from a reservoir by water an important factor in determining the

areal and vertical sweep efficiencies is the difference in the mobilities of the twofluids The mobility of any fluid in a porous medium such as reservoir rock is directlyproportional to its velocity of flow and is equal to the effective permeability to thatfluid divided by the fluid viscosity For oil this would be equal to k0 0 Because our

reservoir permeability information is available in terms of relative permeability themobility is expressed as

(2) The mobility ratio is defined as the mobility of the displacing phase in the portion of the reservoircontacted by the injected fluid divided by the mobility of the displaced phase in the non-invadedportion of the reservoir In the case of water displacing oil (waterflooding)

If M is less than or equal to one it means that the oil is capable of traveling at the same or greatervelocity than the water under the same conditions The water therefore will not bypass the oiland will instead push it ahead If M is greater than one the water is capable of moving faster thanthe oil and will bypass some of the oil leaving unswept areas behind We can see that anincrease in the viscosity of the oil will cause the mobility ratio to increase This is logical as wecan imagine attempting to push a viscous heavy oil through a pore system and having the lessviscous water finger through or around the slow moving oil An obvious approach to improving



the mobility ratio would be to decrease the difference in oil and water viscosities by increasingthe water viscosity andor decreasing the oil viscosity

We can also imagine that the areal sweep of water through an oil reservoir would

also depend upon where the water is injected relative to where the oil is produced Awide variety of flooding patterns have been used in the oil field and some of these

are reproduced in Figure 1 and Figure 2

Figure 1

Laboratory models have enabled researchers to measure the areal sweep efficiencies

for different mobility ratioflood pattern combinations



Figure 2

For example if we have wells spaced in a five-spot pattern and are producing from a

homogeneous uniform reservoir the areal sweep efficiency at the point in time whenthe displacing phase breaks through to the producing well has been shown to beabout 68 to 72 for a mobility ratio of 10 Figure 3 (M=10) shows in stages the

sweep of a five-spot model as the injected fluid moves to breakthrough



Figure 3

Figure 4 shows how the areal sweep efficiency at breakthrough for this pattern

changes with mobility ratio



Figure 4

We are interested in the sweep efficiency at breakthrough because generally littleadditional oil is recovered by injecting water after a channel of water flow existsbetween injector and producer

It should also be pointed out that areal variations in permeability will have a major

effect on the ability of the displacing phase to sweep the reservoir For this reasonthe reservoir engineer now works closely with the development geologist to definethe reservoir environment

Vertical sweep efficiency (EVS) also depends upon the mobility ratio and in additionon the vertical distribution of permeability within the reservoir The laboratory

determined areal sweep efficiencies mentioned above assume a homogeneousreservoir If the permeability varies vertically as is often the case in a real reservoiran injected fluid will move through the reservoir with an irregular vertical front

moving more rapidly in the more permeable sections The sweep efficiency atbreakthrough will depend on the degree of difference in permeabilities and on themobility ratio Figure 5 shows how changes in the mobility ratio can affect vertical

sweep



Figure 5

When the mobility ratio is greater than 10 the displacing phase has more mobilitythan the displaced phase Thus as displacing fluid enters the high permeability zone

the total resistance to flow decreases in that zone and the flow in that zone

increases When breakthrough eventually occurs a greater portion of the lowerpermeability zone is left unswept When M is less than 10 the channeling effect isless pronounced

DISPLACEMENT EFFICIENCY Unfortunately simply getting the injected fluid to

contact a given volume of the reservoir does not mean that all the oil in that volume

will be displaced The displacement efficiency refers to the fraction of the oil in placethat is swept from a unit volume of the reservoir Displacement efficiency is a

function of fluid viscosities and the relative permeability characteristics of thereservoir rock (mobility ratio) of the wettability of the rock and of pore geometry

Wettability pertains to whether water or oil preferentially wets the reservoir rockgrains In an oil-wet reservoir oil is preferentially adsorbed on the grain surface Fora water-wet reservoir the converse is true Oil reservoirs range from strongly oil-wet through intermediate gradations to strongly water-wet Most are water-wet In

a water-wet system the oil exists in the middle of the pore system with waterdistributed between it and the rock surfaces As water displaces oil through the



porous medium some of the oil is left in globules at the center of the pores In an

oil-wet system the residual oil clings to the rock grains and is left as a film on the

pore walls Figure 6 ((a) water-wet rock (b) oil-wet rock) illustrates the difference

between these two extremes

Figure 6

We can also see the role of wettability in the capillary effects in a reservoir Figure 7

shows a microscopic view of a water-wet pore system



Figure 7

As the invading water reaches the intersection of the large diameter and smallerdiameter pore channels the individual pores pull the water phase ahead in a

manner similar to that of water rising in a capillary tube The advance is greatest in

the pore with the smallest radius Once the water-oil interface has reached acapillary equilibrium position in a pore the pressure gradient pushes it along toward

the outlet The interface reaching the outlet first (probably the smaller capillary)

rushes through the outlet to the next pore and isolates the oil in the other capillaryOn a three-dimensional level the isolated oil is referred to as ganglia and collectivelyit makes up the residual oil saturation in the swept portions of the reservoir The

isolated oil will not be moved by normal pressure gradients in the reservoir unless

the resistance of the water-oil interface can be broken down by reducing the inter-facial tension at the interface

The relative permeability characteristics of a reservoir rock and the fluid viscositiesare the properties used to determine the displacement efficiency As we mentioned

in section 212 relative permeability is a measure of the rocks ability to conduct

one fluid when two (or more) fluids are present It reflects the composite effect of pore geometry wettability fluid distribution and saturation history on the fluid flow

behavior of the rock-fluid system Figure 6 shows examples of relative permeabilitycurves for both strongly water-wet and strongly oil-wet rocks



The displacement efficiency for a waterflood can be calculated using the fluid

viscosities and the water-oil relative permeability characteristics The procedure is to

construct a fractional flow curve the fractional flow of water versus water saturationIf this approach is utilized it can be shown that the displacement efficiency atbreakthrough is higher the lower the oil viscosity For a strongly water-wet reservoir

with relative permeability characteristics as shown in Figure 8

Figure 8

if the oil viscosity is about 20 cp (0002 Pa s) or lower the displacement of oil by

the water is piston-like that is all the recoverable oil in the swept portion isdisplaced at breakthrough Usually the displacement is not so efficient and theaverage water saturation in the invaded portion of the rock increases with continued

injection ( Figure 9 )



Figure 9

Figure 10 and Figure 11 shows schematically the difference between ideal and non-

ideal displacement



Figure 10

The flood front is shown as a vertical line representing the discontinuity of water

saturation behind and ahead of the front



Figure 11

We might find that based on measurements of relative permeability fluidviscosities and permeability distributions the expected sweep efficiency factors for aproposed waterflood are

ED = 075 EAS = 085 EVS = 080 Our overall recovery efficiency is then

ED EAS EVS = 075 x 085 x 080 = 051 or 51 and we might expect to recover 51 of the oil in place as a result of water-flooding This meansthat only half the oil can be recovered even when we have a good level of efficiencies The taskof recovering the balance of the oil is formidable

Enhanced oil recovery methods attempt to improve these efficiency factors by

bull reducing the mobility ratio by increasing water viscosity

bull reducing the mobility ratio by decreasing oil viscosity

bull altering the interfacial tension of the water-oil interface and

bull improving the relative permeability characteristics



Table 1 (below) lists the enhanced recovery methods that are of importance today

Enhanced oil recovery methods

Chemical Recovery Processes

bull Polymer flooding

bull Surfactant-polymer flooding (microemulsion flooding)

bull Caustic flooding

Thermal recovery processes

bull Steam flooding

bull In-situ combustion

Miscible recovery processes

bull Miscible hydrocarbon displacement

bull Carbon dioxide injection

bull Inert gas injection

Table 14 (above)



Enhanced Oil Recovery (EOR)

Enhanced oil recovery processes attempt to alter the physical forces holding oil in a

reservoir by improving the volumetric sweep efficiency through mobility ratio controland by improving the displacement efficiency through surface active agents heat

and miscible displacement Regardless of laboratory performance the value of allenhanced oil recovery techniques ultimately is determined by the degree to whichthey are economically applicable in the field It may be possible to maximizerecovery by initiating an enhanced recovery project early in the life of a field but the

additional early capital cost with delayed return may make it economically

unattractive Economic applicability is critically dependent on an accurate geologicalinterpretation of the reservoir By providing guidance throughout the development of a reservoir geologists can help provide for the maximum recovery of the oil they

have found




Several approaches that improve the mobility ratio in a waterflood and reduce theinterfacial tension at the oil-water interface have involved the addition of chemicalagents to injected water

POLYMER FLOODING An obvious approach to improving the mobility ratio wouldbe to increase the effective viscosity of the injected water before injection into thereservoir This can be done by the addition of long chain molecules called polymers(the jelly-like component in your tube of shampoo) Although there are many

polymers available for this approach the most economically attractive examples are

polysaccharides (xanthan gum) and polyacrylamides The polysaccharides areproduced by microbial action while the polyacrylamides are synthetically producedchemicals with a wide range of molecular weights and chain lengths Polyacrylamides

are relatively economical and stable but are sensitive to shear and salinityPolysaccharides stand up to salinity and shearing rates but are prone to bacterial andthermal degradation A commercial polymer solution is a non-Newtonian fluid Its

behavior is generally characterized as pseudoplastic that is its resistance to flow

and its apparent viscosity is lower at low flow velocities than at high flow velocitiesHowever at very high velocities such as those that may exist near the injectionwells the polymer solution can act as a dilatant fluid and its apparent viscosity will

increase (Where high velocities might cause bypassing the polymer solutionincreases viscosity and slows down) Figure 1 (comparison of viscosities of two typesof polymers at 1000 ppm in 10 NaCl at 74deg F) shows the effect of polymer solution

concentration on viscosity at a given shear rate (Normal formation water viscosity is

about 2 to 2 cp)

In addition to increasing water viscosity and thereby reducing the mobility ratio

polymer flooding also improves areal and vertical sweep efficiency by reducing therelative permeability to the polymer solution Apparently this is accomplished byadsorption of the polymer onto the rock grains by entrapment of polymer molecules

in pore throats and by the inability of the polymer-laden solution to enter small porechannels Overall the reduction in permeability allows the preferential filling of thehigh permeability streaks or zones in the reservoir with a viscous slug lowering thevelocity of flow and increasing the sweep of the lower permeability zones

Polymer flooding does not decrease the residual oil saturation significantly in the

swept zone Its primary importance is in the improvement of the areal and vertical

sweep efficiencies and the acceleration of oil production before the economic limit of water-oil production ratio is reached Polymer flooding is most efficient when begunearly in the life of a waterflood particularly when mobility ratios are poor (2 to 20)

and significant permeability variations exist

SURFACTANT POLYMER FLOODING Surface active agents or surfactants arecompounds that can act to reduce the interfacial tension at the interface between theoil and water in the reservoir Detergents are examples of an everyday use of

surfactants to allow water to displace oil (and the accompanying dirt) from clothing

dishes etc Reduction in interfacial tension improves the displacement efficiency of the flood and reduces the residual oil saturation Surfactants are usually introducedto a waterflood as components in a water-oilsurfactant solution This solution is also

called a microemulsion or a micellar solution because of the existance of micelles

aggregates of surfactant molecules surrounding microscopic oil droplets in water or



microscopic water droplets in oil A slug of this solution is injected into the reservoir

usually in a high volume (15 to 60 of reservoir pore volume) with a low

concentration or in a low volume (3 to 20 of reservoir pore volume) with a highconcentration

In the low concentration case the reduction in interfacial tension increases oil

recovery gradually with the passage of increasing volumes of surfactant solution Inthe high concentration case the surfactant solution rapidly displaces water and

almost all the oil contacted but it reverts to a low-concentration flood as thesurfactant slug becomes diluted by formation fluids Figure 2 shows schematicallyhow a microemulsion and a polymer solution followed by water injection are used insequence to improve the mobility of the flood

Some surfactant solutions have cosurfactants (usually alcohol) electrolytes or

inorganic salts added to improve performance Surfactant slug size and compositionmust be tailored to the specific reservoir rock and fluid properties Adsorption of surfactants onto the rock surface can be an important reason for slug breakdown

The subject of surfactant solutions is complex and their behavior in the reservoirs is

not easily predicted

CAUSTIC FLOODING The fact that the addition of sodium hydroxide (caustic) toinjection water improves oil recovery for many reservoirs has been recognized formany years Although the process appears simple and relatively inexpensive the

mechanisms involved in displacement of the oil are complicated At present at leastfive methods are believed to act in the process

bull lowering of interfacial tension by reaction of the caustic with acidic

crude oil components usually found in heavier viscous crudes tocreate surfactants in situ

reversal of rock wettability

emulsification of residual oil and entrapment in small pore throats toreduce water mobility and improve areal and vertical sweepefficiency

in-situ emulsification and entrainment of residual oil into the flowingcaustic water phase carrying the oil out of the rock

solubilization of rigid films which form at the oil-water interfaceallowing mobilization of the residual oil

The most commonly used caustic chemical is sodium hydroxide although sodiumorthosilicate ammonium hydroxide and others have been suggested The reaction

of the reservoir rock with the chemical is an important factor that must beconsidered in designing a caustic flood Crude oil acidity is also important Also thehardness of the injection water must be controlled or else precipitates of calcium

hydroxide may form plugging the injection wells Low concentration caustic solutions(05 to 20 wt) appear to offer the best results for interfacial tension reduction



Chemically enhanced oil recovery processes act to improve mobility ratio increase

volumetric sweep and improve displacement efficiency Compared with other

methods recovery costs can be somewhat high except for caustic flooding Table 1(below) shows some generalized reservoir criteria for screening reservoir candidates

Screening criteria for chemical processes

SurfactantPolymer

Oil properties bull Gravity deg API gt25

bull Viscosity cp lt30

bull Composition light intermediates desired

Reservoir bull Oil saturation gt30

characteristics bull Formation type sandstone preferred

bull Net thickness ft (m) gt10 (3)

bull Average gt20

permeability md

bull Depth ft (m) lt8000 (2400)

bull Temperature deg F (K) lt175 (353)

Polymer Alkaline

(caustic)

Oil properties bull Gravity deg API gt25 13-35

bull Viscosity cp lt150 lt200

bull Composition not critical some

organic

acids

Reservoir

characteristics bull Oil saturation gt10 mobile oil above waterflood residual



bull Formation type sandstone preferred sandstone

carbonate preferred

possible

bull Net thickness ft (m) not critical not critical

bull Average permeability gt10 (normally) gt20

bull Depth ft (m) lt9000 (2700) lt9000 (2700)

bull Temperature deg F (k) lt200(367) lt200 (367)

Table 1 (Taber and Martin 1983)



Thermal Recovery Processes

Thermal processes attack the problem of an unfavorable mobility ratio by heating thereservoir and its fluids either by adding heat via steam or hot water or by

generating heat within the reservoir by burning some of the oil in the formation The

most important effect of adding heat is the sharp reduction in the oil viscosity and

the resulting decrease in the mobility ratio Figure 1 shows the effect of temperatureon oil viscosity

Figure 1

Note that the viscosity of a heavy 10API crude oil at 60 F (2887 K) is about

100000 cp (100 Pa s) but drops to about 10 cp at 360iexclF (001 Pa s at 4554 K)Increasing the reservoir fluid temperature also reduces interfacial tension andincreases the relative permeability to oil It also vaporizes some of the oil (lighter

ends) as it moves forward in the formation where it condenses to form animproved oil

STEAM FLOODING Steam flooding consists of the continuous injection of steam

into a reservoir with an injection-production well pattern similar to a waterflood Asthe steam moves out into the reservoir away from the injection well its temperature



drops from heat losses and it begins to condense as hot water ( Figure 2 ) In the

steam zone oil is actually vaporized In the hot water zone the oil expands its

viscosity drops the residual saturation is lowered and the relative permeabilityincreased All of these effects improve oil recovery

Figure 2

An alternative to pattern steam flooding is to inject steam into a well shut it in for a

period of time and then back-produce the less viscous hot oil and water located nearthe wellbore

This cycle is repeated many times and is termed cyclic steam injection huff andpuff or steam stimulation Operators can begin with this procedure but later mustultimately convert to a pattern steam flood to maintain oil production rates

Steam flooding is currently the principal enhanced oil recovery technique As of

1995 the worldrsquos largest steamflood project was in the Duri field in Indonesiaproducing 300000 STB of oil per day Other major steamflood areas include theUnited States (particularly California) and Venezuela

The primary factors limiting the application of steam injection to oil reservoirs are

depth and thickness depth because of the critical pressure of steam (3202 psia or22086 kPa) and thickness because of excessive heat loss to underlying andoverlying rock formations in the reservoir Table 1 (below) gives some data

comparing successful steam floods worldwide One of the California examples the



South Belridge field was developed in the 1940s but by 1952 production of the

heavy 13 API 1600 cp viscosity crude using normal production methods had peaked

Cyclic steam injection was introduced and increased rates during the late 1960s butthe effectiveness of successive steam cycles diminished Continuous steam injectionbegan in 1969 and within 4 12 years the oil recovery exceeded the total oil

recovered during the preceding 25 years by both primary recovery and cyclic steam

stimulation (Van Poollen 1980)

Field- Sand Depth Reservoir h

(ft) Pressure Net Pay

(psig) (ft)

Kern River CA 900 35 60

Inglewood CA 1000 120 43

Brea B CA 4600 100 189

Coalinga CA 1500 300 35

Yorba Linda CA 2100 200 32

San Ardo Auginac CA 2350 250 150

Mount Poso CA 1800 100 60

Yorba Linda CA 650 325

South Beldridge CA 1100 180 91

Midway-Sunset CA 1600 50 350

Schoonebeck Holland 2600 120 83

Slocum TX 535 110 40

Smackover AR 2000 5 20

Tia Juana Venezuela 1600 300 125

Winkleman Dome WY 1200 210 73

Field- Sand 0 k kh0

Oil Vis- Permeability (md-ftcp)

cosity (cp) (md)





Brea B CA 6 70 2200




Mount Poso CA 280 15000 3210

Yorba Linda CA 6400+ 600




Slocum TX 1300 3500 1080




Field- Sand Oil Content SteamOil Oil Steam

(bblacre-ft) Ratio Ratio

(bblbbl) (bblbbl)



Brea B CA 940 48 021



San Ardo Auginac CA 1690




Yorba Linda CA


Midway-Sunset CA


Slocum TX 1400 56 018




Table 1 (above)

I N-SITU COMBUSTION Another way of obtaining the beneficial effects of heat inthe reservoir is to generate the heat in situ or within the reservoir itself This can be

done by injecting oxygen (air) into the reservoir by using compressors and thenigniting the crude oil-oxygen mixture Continued injection of air will cause theburning front or combustion zone to propagate out into the reservoir heating the oil

ahead of it and producing steam and hot gases that drive the oil out of thereservoir There are three basic forms of in-situ combustion dry forwardcombustion reverse combustion and wet combustion Figure 3 shows schematicallyhow the combustion zone is propagated outward in the direction of the injection in

the dry forward combustion process



Figure 3

Behind the combustion zone the sand is burned out and the combustion zone is thehottest portion of the flood Immediately ahead of the combustion zone is the coke

region where the heavier portions of the crude oil are all that remain to be burned

after the heat from the approaching combustion zone has cooked the oil Ahead of the coke zone are steam and hot water generated by heat from the combustionzone light hydrocarbons distilled from the reservoir crude and a bank of oil being

pushed ahead by the front

In the reverse combustion process the air is injected from the opposite direction but

ignition is at the same point now the producing well This approach forces the oil tomove through the preheated reservoir allowing easier flow of extremely heavy

crudes However more of the lighter portions of the crude are consumed by theprocess

Wet combustion is an attempt to transfer the heat from the burned out portion of the

reservoir behind the combustion front in a dry forward process to the oil ahead of theburning zone Water is injected after the front has been propagated and is converted

into steam in the reservoir by the hot rock behind the combustion zone This partiallyquenches the combustion zone and spreads the generated heat more evenly throughthe reservoir

Important considerations in selection of reservoirs for in-situ combustion andsteamflooding processes are generalized in Table 2 (below) Vertical sweep in very

thick formations is likely to be poor due to segregation of the steam and combustiongases In-situ combustion is particularly appropriate when there is less rock to heat

that is when the porosity and oil saturations are high Economic comparisons of in-



situ combustion versus steam injection depend heavily on the cost of fuel to producesteam

Screening criteria for thermal processes

Combustion Steamflooding

Oil properties Gravity API lt40 lt25(10-25 normally)

bull Viscosity cp lt1000 gt20

bull Composition some asphaltic not criticalcomponents

Reservoir bull Oil saturation gt40-50 gt40-50

characteristics bull Formation type sand or sandstone sand or sandstone

with high porosity with high porosity bull Net thicknessft(m) gt10(3) gt20(6)

bull Average

permeability md gt100 gt200

bull Depth ft (m) gt500 (150) gt300-5000

(90-1500)

bull Temperature gt150 (340)

F (K) not critical

Transmissibilitygt20 md ftcp


Thermal processes rely on heat primarily to reduce oil viscosity but also to reduceinterfacial tension improve relative permeability and vaporize and expand portions

of the oil Both volumetric sweep efficiency and displacement efficiency areimproved



Miscible Recovery Processes

Washing ones hands with detergent after an oil change will get the worst of it off

but a little gasoline (while not recommended) will clean up every trace of oil Thatsthe difference between surfactants and miscible displacement Miscibility means thatthe interface between the displacing and displaced fluids disappears so that the oil is

dissolved and the result is 100 displacement efficiency Of course a gasoline floodis absurd from an economic standpoint but several other methods approach the goalof complete oil displacement These methods differ primarily in the type of solvent

used to achieve miscibility refined hydrocarbons liquified hydrocarbon gasescarbon dioxide or inert gases

MISCIBLE HYDROCARBON DISPLACEMENT There are three different miscible

hydrocarbon displacement processes the Miscible Slug Process the Enriched GasProcess and the High-Pressure Lean Gas Process In the Miscible Slug Process a

propane slug of perhaps 5 of the reservoir pore volume is injected followed by

natural gas or gas and water to drive the solvent through the reservoir In theEnriched Gas Process a slug of hydrocarbon gas with large amounts of C2-C6

components is injected in place of the propane slug The High-Pressure Lean GasProcess substitutes a lean natural gas mixture in order to cause vaporization of the

C2-C6 components from the oil to the gas forming a miscible phase at high-pressure Figure 1 shows schematically what happens sequentially in a Miscible Slug Process

Figure 1



Unfortunately the solvent becomes con-cent rated with oil as it moves through the

reservoir and its ability to dissolve the oil is reduced Another major problem is the

poor mobility ratio that exists between the solvent and the gas that follows itAlternate injection of gas and water is used in an attempt to improve this situationThe lean gas or enriched gas processes are particularly suited for areas where there

is no ready gas market and the necessary size of the propane slug is economically

unattractive

CARBON DIOXIDE FLOODING Carbon dioxide is soluable in both oil and waterand can be miscible with oil making it a candidate for use in miscible floodsMiscibility of carbon dioxide and oil is pressure dependent however and not all

carbon dioxide floods are miscible processes In addition to miscibility other factorsthat allow carbon dioxide to improve oil recovery include

reduction of crude oil viscosity

swelling of the crude oil

increased injectivity and

solution-gas drive effects

Carbon dioxide flooding can be applied in a variety of ways continuous injection of carbon dioxide

carbon dioxide injection followed by a less expensive gas

carbon dioxide injection followed by water and

simultaneous or alternate injection of carbon dioxide and water (called

the WAG process)

Although carbon dioxide is not immediately miscible with crude oil under the right conditions oftemperature and pressure the carbon dioxide will extract components from the oil in a mannersimilar to that mentioned earlier for lean gas displacement This mixture forms a miscible frontthat efficiently sweeps the oil to the producing wells The required pressure for miscibility varieswith oil composition and temperature For example a 30 API oil requires 1200 psi while a 27 APIoil requires 4000 psi at 120F

Pipelines from Colorado to west Texas are now carrying CO2 to fields that arecurrently undergoing or will soon undergo CO2 injection

INERT GAS INJECTION The use of nitrogen or flue gas as a cheaper substitute

for carbon dioxide or light hydrocarbon mixtures has been tested in the laboratoryand the field Combustion gases from boiler flues or gas engine exhausts areprimarily nitrogen and carbon dioxide and have a larger volume than the gas burned

to produce them Nitrogen does not achieve miscibility as easily as carbon dioxide

but it can effectively displace the reservoir gas for sale leaving the inert gas in thereservoir at abandonment



An inert gas injection project in the Hawkins field Texas is designed so that steam

boiler exhaust gas is injected into the gas cap of a water drive reservoir to prevent

loss of gas cap pressure The steam boilers that produce the flue gas also driveturbines which in turn power compressors to inject the inert gas (Van Poollen1980)

Table 1 (below) gives some generalized criteria for the selection of candidatereservoirs for miscible recovery projects While miscible displacement holds the

promise of improving the displacement efficiency in most applications the cost of themiscible fluid is high and much of it is not recoverable Reservoir heterogeneity is animportant factor in all improved recovery projects but particularly so in miscible

displacement processes where discontinuities can result in the bypassing of costlyinjectants

Screening criteria for miscible processes

Hydrocarbon

Oil properties Gravity API gt35

Viscosity cp lt10

Composition high of C2 - C7

Reservoir characteristics

Oil saturation gt30 PV

Formation type sandstone or carbonate

Net thickness ft (m) thin unless dipping

Averagepermeability md

not critical

Depth ft (m)

gt2000 (600) for LPG to gt5000

(1500) for HP Gas Temperature F (K) not critical

Nitrogen amp Flue Gas Carbon Dioxide

Oil properties Gravity API

gt24 gt35 for N2

gt26

Viscosity cp lt10 lt15

Composition high of C1 - C7 high of C5 - C12

Reservoir characteristics Oil saturation gt30 PV gt30 PV

Formation type sandstone or carbonate sandstone orcarbonate

Net thickness ft (m) thin unless dipping thin unlessdipping


not critical not critical

Depth ft (m) gt4500 (1370) gt2000 (6000)

Temperature F (K) not critical not critical






Waterflooding and Recovery Efficiency

All improved recovery methods involve the injection of fluids into the reservoir via

one or more wells and the production of oil (and perhaps ultimately the injectedfluid) from one or more other wells The methods differ in the nature of the fluidsused and the physical changes they bring about in the reservoir but water usually

plays a part in helping to displace the oil The amount of oil recovered (and obviouslythe success of the project) is dependent upon the percentage of oil in place that iscontacted and moved by the displacing fluid This concept is represented by the

equation

Np = N EV ED (1)

where EV = EAS EVS

The oil recovered (Np) is the product of the volume of the oil in place (N) the

fraction that is contacted (EV) and the fraction of the oil contacted that is displaced(ED) The volumetric sweep efficiency (EV) given as a fraction is the product of the

areal sweep efficiency (EAS) and the vertical sweep efficiency (EVS) Usually all of these values (except N) increase during the life of an improved recovery projectuntil an economic limit is reached Enhanced recovery methods differ in the manner

in which they attempt to improve either EV or ED We will discuss each factorseparately

VOLUMETRIC SWEEP EFFICIENCY The volumetric sweep efficiency (EV) at a

given point in time is the fraction of the total reservoir volume contacted by theinjected fluid during an improved recovery project It is the composite of the arealsweep efficiency (EAS) and the vertical sweep efficiency (EVS)

When oil is swept from a reservoir by water an important factor in determining the

areal and vertical sweep efficiencies is the difference in the mobilities of the twofluids The mobility of any fluid in a porous medium such as reservoir rock is directlyproportional to its velocity of flow and is equal to the effective permeability to thatfluid divided by the fluid viscosity For oil this would be equal to k0 0 Because our

reservoir permeability information is available in terms of relative permeability themobility is expressed as

(2) The mobility ratio is defined as the mobility of the displacing phase in the portion of the reservoircontacted by the injected fluid divided by the mobility of the displaced phase in the non-invadedportion of the reservoir In the case of water displacing oil (waterflooding)

If M is less than or equal to one it means that the oil is capable of traveling at the same or greatervelocity than the water under the same conditions The water therefore will not bypass the oiland will instead push it ahead If M is greater than one the water is capable of moving faster thanthe oil and will bypass some of the oil leaving unswept areas behind We can see that anincrease in the viscosity of the oil will cause the mobility ratio to increase This is logical as wecan imagine attempting to push a viscous heavy oil through a pore system and having the lessviscous water finger through or around the slow moving oil An obvious approach to improving







Figure 1





Figure 2






Figure 3





Figure 4







sweep



Figure 5
















Figure 6





Figure 7


















Figure 8






Figure 9


ideal displacement



Figure 10





Figure 11


















bull Steam flooding






Table 14 (above)









have found













about 2 to 2 cp)










































SurfactantPolymer







bull Average gt20

permeability md



Polymer Alkaline

(caustic)




organic

acids

Reservoir





carbonate preferred

possible













Figure 1











Figure 2


















(psig) (ft)



Brea B CA 4600 100 189













Field- Sand 0 k kh0


cosity (cp) (md)





Brea B CA 6 70 2200




Mount Poso CA 280 15000 3210





Slocum TX 1300 3500 1080






(bblbbl) (bblbbl)



Brea B CA 940 48 021







Yorba Linda CA


Midway-Sunset CA


Slocum TX 1400 56 018




Table 1 (above)







Figure 3

























bull Average



(90-1500)


F (K) not critical


















Figure 1







unattractive











the WAG process)
















Hydrocarbon


Viscosity cp lt10







not critical

Depth ft (m)





gt24 gt35 for N2

gt26








Depth ft (m) gt4500 (1370) gt2000 (6000)











Figure 1





Figure 2






Figure 3





Figure 4







sweep



Figure 5
















Figure 6





Figure 7


















Figure 8






Figure 9


ideal displacement



Figure 10





Figure 11


















bull Steam flooding






Table 14 (above)









have found













about 2 to 2 cp)










































SurfactantPolymer







bull Average gt20

permeability md



Polymer Alkaline

(caustic)




organic

acids

Reservoir





carbonate preferred

possible













Figure 1











Figure 2


















(psig) (ft)



Brea B CA 4600 100 189













Field- Sand 0 k kh0


cosity (cp) (md)





Brea B CA 6 70 2200




Mount Poso CA 280 15000 3210





Slocum TX 1300 3500 1080






(bblbbl) (bblbbl)



Brea B CA 940 48 021







Yorba Linda CA


Midway-Sunset CA


Slocum TX 1400 56 018




Table 1 (above)







Figure 3

























bull Average



(90-1500)


F (K) not critical


















Figure 1







unattractive











the WAG process)
















Hydrocarbon


Viscosity cp lt10







not critical

Depth ft (m)





gt24 gt35 for N2

gt26








Depth ft (m) gt4500 (1370) gt2000 (6000)







Figure 2






Figure 3





Figure 4







sweep



Figure 5
















Figure 6





Figure 7


















Figure 8






Figure 9


ideal displacement



Figure 10





Figure 11


















bull Steam flooding






Table 14 (above)









have found













about 2 to 2 cp)










































SurfactantPolymer







bull Average gt20

permeability md



Polymer Alkaline

(caustic)




organic

acids

Reservoir





carbonate preferred

possible













Figure 1











Figure 2


















(psig) (ft)



Brea B CA 4600 100 189













Field- Sand 0 k kh0


cosity (cp) (md)





Brea B CA 6 70 2200




Mount Poso CA 280 15000 3210





Slocum TX 1300 3500 1080






(bblbbl) (bblbbl)



Brea B CA 940 48 021







Yorba Linda CA


Midway-Sunset CA


Slocum TX 1400 56 018




Table 1 (above)







Figure 3

























bull Average



(90-1500)


F (K) not critical


















Figure 1







unattractive











the WAG process)
















Hydrocarbon


Viscosity cp lt10







not critical

Depth ft (m)





gt24 gt35 for N2

gt26








Depth ft (m) gt4500 (1370) gt2000 (6000)







Figure 3





Figure 4







sweep



Figure 5
















Figure 6





Figure 7


















Figure 8






Figure 9


ideal displacement



Figure 10





Figure 11


















bull Steam flooding






Table 14 (above)









have found













about 2 to 2 cp)










































SurfactantPolymer







bull Average gt20

permeability md



Polymer Alkaline

(caustic)




organic

acids

Reservoir





carbonate preferred

possible













Figure 1











Figure 2


















(psig) (ft)



Brea B CA 4600 100 189













Field- Sand 0 k kh0


cosity (cp) (md)





Brea B CA 6 70 2200




Mount Poso CA 280 15000 3210





Slocum TX 1300 3500 1080






(bblbbl) (bblbbl)



Brea B CA 940 48 021







Yorba Linda CA


Midway-Sunset CA


Slocum TX 1400 56 018




Table 1 (above)







Figure 3

























bull Average



(90-1500)


F (K) not critical


















Figure 1







unattractive











the WAG process)
















Hydrocarbon


Viscosity cp lt10







not critical

Depth ft (m)





gt24 gt35 for N2

gt26








Depth ft (m) gt4500 (1370) gt2000 (6000)







Figure 4







sweep



Figure 5
















Figure 6





Figure 7


















Figure 8






Figure 9


ideal displacement



Figure 10





Figure 11


















bull Steam flooding






Table 14 (above)









have found













about 2 to 2 cp)










































SurfactantPolymer







bull Average gt20

permeability md



Polymer Alkaline

(caustic)




organic

acids

Reservoir





carbonate preferred

possible













Figure 1











Figure 2


















(psig) (ft)



Brea B CA 4600 100 189













Field- Sand 0 k kh0


cosity (cp) (md)





Brea B CA 6 70 2200




Mount Poso CA 280 15000 3210





Slocum TX 1300 3500 1080






(bblbbl) (bblbbl)



Brea B CA 940 48 021







Yorba Linda CA


Midway-Sunset CA


Slocum TX 1400 56 018




Table 1 (above)







Figure 3

























bull Average



(90-1500)


F (K) not critical


















Figure 1







unattractive











the WAG process)
















Hydrocarbon


Viscosity cp lt10







not critical

Depth ft (m)





gt24 gt35 for N2

gt26








Depth ft (m) gt4500 (1370) gt2000 (6000)







Figure 5
















Figure 6





Figure 7


















Figure 8






Figure 9


ideal displacement



Figure 10





Figure 11


















bull Steam flooding






Table 14 (above)









have found













about 2 to 2 cp)










































SurfactantPolymer







bull Average gt20

permeability md



Polymer Alkaline

(caustic)




organic

acids

Reservoir





carbonate preferred

possible













Figure 1











Figure 2


















(psig) (ft)



Brea B CA 4600 100 189













Field- Sand 0 k kh0


cosity (cp) (md)





Brea B CA 6 70 2200




Mount Poso CA 280 15000 3210





Slocum TX 1300 3500 1080






(bblbbl) (bblbbl)



Brea B CA 940 48 021







Yorba Linda CA


Midway-Sunset CA


Slocum TX 1400 56 018




Table 1 (above)







Figure 3

























bull Average



(90-1500)


F (K) not critical


















Figure 1







unattractive











the WAG process)
















Hydrocarbon


Viscosity cp lt10







not critical

Depth ft (m)





gt24 gt35 for N2

gt26








Depth ft (m) gt4500 (1370) gt2000 (6000)











Figure 6





Figure 7


















Figure 8






Figure 9


ideal displacement



Figure 10





Figure 11


















bull Steam flooding






Table 14 (above)









have found













about 2 to 2 cp)










































SurfactantPolymer







bull Average gt20

permeability md



Polymer Alkaline

(caustic)




organic

acids

Reservoir





carbonate preferred

possible













Figure 1











Figure 2


















(psig) (ft)



Brea B CA 4600 100 189













Field- Sand 0 k kh0


cosity (cp) (md)





Brea B CA 6 70 2200




Mount Poso CA 280 15000 3210





Slocum TX 1300 3500 1080






(bblbbl) (bblbbl)



Brea B CA 940 48 021







Yorba Linda CA


Midway-Sunset CA


Slocum TX 1400 56 018




Table 1 (above)







Figure 3

























bull Average



(90-1500)


F (K) not critical


















Figure 1







unattractive











the WAG process)
















Hydrocarbon


Viscosity cp lt10







not critical

Depth ft (m)





gt24 gt35 for N2

gt26








Depth ft (m) gt4500 (1370) gt2000 (6000)







Figure 7


















Figure 8






Figure 9


ideal displacement



Figure 10





Figure 11


















bull Steam flooding






Table 14 (above)









have found













about 2 to 2 cp)










































SurfactantPolymer







bull Average gt20

permeability md



Polymer Alkaline

(caustic)




organic

acids

Reservoir





carbonate preferred

possible













Figure 1











Figure 2


















(psig) (ft)



Brea B CA 4600 100 189













Field- Sand 0 k kh0


cosity (cp) (md)





Brea B CA 6 70 2200




Mount Poso CA 280 15000 3210





Slocum TX 1300 3500 1080






(bblbbl) (bblbbl)



Brea B CA 940 48 021







Yorba Linda CA


Midway-Sunset CA


Slocum TX 1400 56 018




Table 1 (above)







Figure 3

























bull Average



(90-1500)


F (K) not critical


















Figure 1







unattractive











the WAG process)
















Hydrocarbon


Viscosity cp lt10







not critical

Depth ft (m)





gt24 gt35 for N2

gt26








Depth ft (m) gt4500 (1370) gt2000 (6000)











Figure 8






Figure 9


ideal displacement



Figure 10





Figure 11


















bull Steam flooding






Table 14 (above)









have found













about 2 to 2 cp)










































SurfactantPolymer







bull Average gt20

permeability md



Polymer Alkaline

(caustic)




organic

acids

Reservoir





carbonate preferred

possible













Figure 1











Figure 2


















(psig) (ft)



Brea B CA 4600 100 189













Field- Sand 0 k kh0


cosity (cp) (md)





Brea B CA 6 70 2200




Mount Poso CA 280 15000 3210





Slocum TX 1300 3500 1080






(bblbbl) (bblbbl)



Brea B CA 940 48 021







Yorba Linda CA


Midway-Sunset CA


Slocum TX 1400 56 018




Table 1 (above)







Figure 3

























bull Average



(90-1500)


F (K) not critical


















Figure 1







unattractive











the WAG process)
















Hydrocarbon


Viscosity cp lt10







not critical

Depth ft (m)





gt24 gt35 for N2

gt26








Depth ft (m) gt4500 (1370) gt2000 (6000)







Figure 9


ideal displacement



Figure 10





Figure 11


















bull Steam flooding






Table 14 (above)









have found













about 2 to 2 cp)










































SurfactantPolymer







bull Average gt20

permeability md



Polymer Alkaline

(caustic)




organic

acids

Reservoir





carbonate preferred

possible













Figure 1











Figure 2


















(psig) (ft)



Brea B CA 4600 100 189













Field- Sand 0 k kh0


cosity (cp) (md)





Brea B CA 6 70 2200




Mount Poso CA 280 15000 3210





Slocum TX 1300 3500 1080






(bblbbl) (bblbbl)



Brea B CA 940 48 021







Yorba Linda CA


Midway-Sunset CA


Slocum TX 1400 56 018




Table 1 (above)







Figure 3

























bull Average



(90-1500)


F (K) not critical


















Figure 1







unattractive











the WAG process)
















Hydrocarbon


Viscosity cp lt10







not critical

Depth ft (m)





gt24 gt35 for N2

gt26








Depth ft (m) gt4500 (1370) gt2000 (6000)







Figure 10





Figure 11


















bull Steam flooding






Table 14 (above)









have found













about 2 to 2 cp)










































SurfactantPolymer







bull Average gt20

permeability md



Polymer Alkaline

(caustic)




organic

acids

Reservoir





carbonate preferred

possible













Figure 1











Figure 2


















(psig) (ft)



Brea B CA 4600 100 189













Field- Sand 0 k kh0


cosity (cp) (md)





Brea B CA 6 70 2200




Mount Poso CA 280 15000 3210





Slocum TX 1300 3500 1080






(bblbbl) (bblbbl)



Brea B CA 940 48 021







Yorba Linda CA


Midway-Sunset CA


Slocum TX 1400 56 018




Table 1 (above)







Figure 3

























bull Average



(90-1500)


F (K) not critical


















Figure 1







unattractive











the WAG process)
















Hydrocarbon


Viscosity cp lt10







not critical

Depth ft (m)





gt24 gt35 for N2

gt26








Depth ft (m) gt4500 (1370) gt2000 (6000)







Figure 11


















bull Steam flooding






Table 14 (above)









have found













about 2 to 2 cp)










































SurfactantPolymer







bull Average gt20

permeability md



Polymer Alkaline

(caustic)




organic

acids

Reservoir





carbonate preferred

possible













Figure 1











Figure 2


















(psig) (ft)



Brea B CA 4600 100 189













Field- Sand 0 k kh0


cosity (cp) (md)





Brea B CA 6 70 2200




Mount Poso CA 280 15000 3210





Slocum TX 1300 3500 1080






(bblbbl) (bblbbl)



Brea B CA 940 48 021







Yorba Linda CA


Midway-Sunset CA


Slocum TX 1400 56 018




Table 1 (above)







Figure 3

























bull Average



(90-1500)


F (K) not critical


















Figure 1







unattractive











the WAG process)
















Hydrocarbon


Viscosity cp lt10







not critical

Depth ft (m)





gt24 gt35 for N2

gt26








Depth ft (m) gt4500 (1370) gt2000 (6000)














bull Steam flooding






Table 14 (above)









have found













about 2 to 2 cp)










































SurfactantPolymer







bull Average gt20

permeability md



Polymer Alkaline

(caustic)




organic

acids

Reservoir





carbonate preferred

possible













Figure 1











Figure 2


















(psig) (ft)



Brea B CA 4600 100 189













Field- Sand 0 k kh0


cosity (cp) (md)





Brea B CA 6 70 2200




Mount Poso CA 280 15000 3210





Slocum TX 1300 3500 1080






(bblbbl) (bblbbl)



Brea B CA 940 48 021







Yorba Linda CA


Midway-Sunset CA


Slocum TX 1400 56 018




Table 1 (above)







Figure 3

























bull Average



(90-1500)


F (K) not critical


















Figure 1







unattractive











the WAG process)
















Hydrocarbon


Viscosity cp lt10







not critical

Depth ft (m)





gt24 gt35 for N2

gt26








Depth ft (m) gt4500 (1370) gt2000 (6000)













have found













about 2 to 2 cp)










































SurfactantPolymer







bull Average gt20

permeability md



Polymer Alkaline

(caustic)




organic

acids

Reservoir





carbonate preferred

possible













Figure 1











Figure 2


















(psig) (ft)



Brea B CA 4600 100 189













Field- Sand 0 k kh0


cosity (cp) (md)





Brea B CA 6 70 2200




Mount Poso CA 280 15000 3210





Slocum TX 1300 3500 1080






(bblbbl) (bblbbl)



Brea B CA 940 48 021







Yorba Linda CA


Midway-Sunset CA


Slocum TX 1400 56 018




Table 1 (above)







Figure 3

























bull Average



(90-1500)


F (K) not critical


















Figure 1







unattractive











the WAG process)
















Hydrocarbon


Viscosity cp lt10







not critical

Depth ft (m)





gt24 gt35 for N2

gt26








Depth ft (m) gt4500 (1370) gt2000 (6000)

















about 2 to 2 cp)










































SurfactantPolymer







bull Average gt20

permeability md



Polymer Alkaline

(caustic)




organic

acids

Reservoir





carbonate preferred

possible













Figure 1











Figure 2


















(psig) (ft)



Brea B CA 4600 100 189













Field- Sand 0 k kh0


cosity (cp) (md)





Brea B CA 6 70 2200




Mount Poso CA 280 15000 3210





Slocum TX 1300 3500 1080






(bblbbl) (bblbbl)



Brea B CA 940 48 021







Yorba Linda CA


Midway-Sunset CA


Slocum TX 1400 56 018




Table 1 (above)







Figure 3

























bull Average



(90-1500)


F (K) not critical


















Figure 1







unattractive











the WAG process)
















Hydrocarbon


Viscosity cp lt10







not critical

Depth ft (m)





gt24 gt35 for N2

gt26








Depth ft (m) gt4500 (1370) gt2000 (6000)


































SurfactantPolymer







bull Average gt20

permeability md



Polymer Alkaline

(caustic)




organic

acids

Reservoir





carbonate preferred

possible













Figure 1











Figure 2


















(psig) (ft)



Brea B CA 4600 100 189













Field- Sand 0 k kh0


cosity (cp) (md)





Brea B CA 6 70 2200




Mount Poso CA 280 15000 3210





Slocum TX 1300 3500 1080






(bblbbl) (bblbbl)



Brea B CA 940 48 021







Yorba Linda CA


Midway-Sunset CA


Slocum TX 1400 56 018




Table 1 (above)







Figure 3

























bull Average



(90-1500)


F (K) not critical


















Figure 1







unattractive











the WAG process)
















Hydrocarbon


Viscosity cp lt10







not critical

Depth ft (m)





gt24 gt35 for N2

gt26








Depth ft (m) gt4500 (1370) gt2000 (6000)











SurfactantPolymer







bull Average gt20

permeability md



Polymer Alkaline

(caustic)




organic

acids

Reservoir





carbonate preferred

possible













Figure 1











Figure 2


















(psig) (ft)



Brea B CA 4600 100 189













Field- Sand 0 k kh0


cosity (cp) (md)





Brea B CA 6 70 2200




Mount Poso CA 280 15000 3210





Slocum TX 1300 3500 1080






(bblbbl) (bblbbl)



Brea B CA 940 48 021







Yorba Linda CA


Midway-Sunset CA


Slocum TX 1400 56 018




Table 1 (above)







Figure 3

























bull Average



(90-1500)


F (K) not critical


















Figure 1







unattractive











the WAG process)
















Hydrocarbon


Viscosity cp lt10







not critical

Depth ft (m)





gt24 gt35 for N2

gt26








Depth ft (m) gt4500 (1370) gt2000 (6000)








carbonate preferred

possible













Figure 1











Figure 2


















(psig) (ft)



Brea B CA 4600 100 189













Field- Sand 0 k kh0


cosity (cp) (md)





Brea B CA 6 70 2200




Mount Poso CA 280 15000 3210





Slocum TX 1300 3500 1080






(bblbbl) (bblbbl)



Brea B CA 940 48 021







Yorba Linda CA


Midway-Sunset CA


Slocum TX 1400 56 018




Table 1 (above)







Figure 3

























bull Average



(90-1500)


F (K) not critical


















Figure 1







unattractive











the WAG process)
















Hydrocarbon


Viscosity cp lt10







not critical

Depth ft (m)





gt24 gt35 for N2

gt26








Depth ft (m) gt4500 (1370) gt2000 (6000)












Figure 1











Figure 2


















(psig) (ft)



Brea B CA 4600 100 189













Field- Sand 0 k kh0


cosity (cp) (md)





Brea B CA 6 70 2200




Mount Poso CA 280 15000 3210





Slocum TX 1300 3500 1080






(bblbbl) (bblbbl)



Brea B CA 940 48 021







Yorba Linda CA


Midway-Sunset CA


Slocum TX 1400 56 018




Table 1 (above)







Figure 3

























bull Average



(90-1500)


F (K) not critical


















Figure 1







unattractive











the WAG process)
















Hydrocarbon


Viscosity cp lt10







not critical

Depth ft (m)





gt24 gt35 for N2

gt26








Depth ft (m) gt4500 (1370) gt2000 (6000)










Figure 2


















(psig) (ft)



Brea B CA 4600 100 189













Field- Sand 0 k kh0


cosity (cp) (md)





Brea B CA 6 70 2200




Mount Poso CA 280 15000 3210





Slocum TX 1300 3500 1080






(bblbbl) (bblbbl)



Brea B CA 940 48 021







Yorba Linda CA


Midway-Sunset CA


Slocum TX 1400 56 018




Table 1 (above)







Figure 3

























bull Average



(90-1500)


F (K) not critical


















Figure 1







unattractive











the WAG process)
















Hydrocarbon


Viscosity cp lt10







not critical

Depth ft (m)





gt24 gt35 for N2

gt26








Depth ft (m) gt4500 (1370) gt2000 (6000)














(psig) (ft)



Brea B CA 4600 100 189













Field- Sand 0 k kh0


cosity (cp) (md)





Brea B CA 6 70 2200




Mount Poso CA 280 15000 3210





Slocum TX 1300 3500 1080






(bblbbl) (bblbbl)



Brea B CA 940 48 021







Yorba Linda CA


Midway-Sunset CA


Slocum TX 1400 56 018




Table 1 (above)







Figure 3

























bull Average



(90-1500)


F (K) not critical


















Figure 1







unattractive











the WAG process)
















Hydrocarbon


Viscosity cp lt10







not critical

Depth ft (m)





gt24 gt35 for N2

gt26








Depth ft (m) gt4500 (1370) gt2000 (6000)









Brea B CA 6 70 2200




Mount Poso CA 280 15000 3210





Slocum TX 1300 3500 1080






(bblbbl) (bblbbl)



Brea B CA 940 48 021







Yorba Linda CA


Midway-Sunset CA


Slocum TX 1400 56 018




Table 1 (above)







Figure 3

























bull Average



(90-1500)


F (K) not critical


















Figure 1







unattractive











the WAG process)
















Hydrocarbon


Viscosity cp lt10







not critical

Depth ft (m)





gt24 gt35 for N2

gt26








Depth ft (m) gt4500 (1370) gt2000 (6000)







Yorba Linda CA


Midway-Sunset CA


Slocum TX 1400 56 018




Table 1 (above)







Figure 3

























bull Average



(90-1500)


F (K) not critical


















Figure 1







unattractive











the WAG process)
















Hydrocarbon


Viscosity cp lt10







not critical

Depth ft (m)





gt24 gt35 for N2

gt26








Depth ft (m) gt4500 (1370) gt2000 (6000)







Figure 3

























bull Average



(90-1500)


F (K) not critical


















Figure 1







unattractive











the WAG process)
















Hydrocarbon


Viscosity cp lt10







not critical

Depth ft (m)





gt24 gt35 for N2

gt26








Depth ft (m) gt4500 (1370) gt2000 (6000)
















bull Average



(90-1500)


F (K) not critical


















Figure 1







unattractive











the WAG process)
















Hydrocarbon


Viscosity cp lt10







not critical

Depth ft (m)





gt24 gt35 for N2

gt26








Depth ft (m) gt4500 (1370) gt2000 (6000)


















Figure 1







unattractive











the WAG process)
















Hydrocarbon


Viscosity cp lt10







not critical

Depth ft (m)





gt24 gt35 for N2

gt26








Depth ft (m) gt4500 (1370) gt2000 (6000)











unattractive











the WAG process)
















Hydrocarbon


Viscosity cp lt10







not critical

Depth ft (m)





gt24 gt35 for N2

gt26








Depth ft (m) gt4500 (1370) gt2000 (6000)














Hydrocarbon


Viscosity cp lt10







not critical

Depth ft (m)





gt24 gt35 for N2

gt26








Depth ft (m) gt4500 (1370) gt2000 (6000)








Documents

3 Improved Oil Recovery.pdf