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Characteristics of Formation Damage and

Variations of Reservoir Properties duringSteam Injection in Heavy Oil ReservoirZ.-X. Pang

ab, H.-Q. Liu

a& X.-L. Liu

b

a

MOE Key Laboratory of Petroleum Engineering, Faculty ofPetroleum Engineering , China University of PetroleumBeijing ,

Beijing, ChinabResearch Center of Post-doctor, Liaohe Oilfield, CNPC, Panjin ,

Liaoning, China

Published online: 23 Feb 2010.

To cite this article:Z.-X. Pang , H.-Q. Liu & X.-L. Liu (2010) Characteristics of Formation Damage andVariations of Reservoir Properties during Steam Injection in Heavy Oil Reservoir, Petroleum Science

and Technology, 28:5, 477-493, DOI: 10.1080/10916460902780335

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Petroleum Science and Technology, 28:477493, 2010

Copyright Taylor & Francis Group, LLC

ISSN: 1091-6466 print/1532-2459 online

DOI: 10.1080/10916460902780335

Characteristics of Formation Damage andVariations of Reservoir Properties during Steam

Injection in Heavy Oil Reservoir

Z.-X. PANG,1;2 H.-Q. LIU,1 AND X.-L. LIU2

1MOE Key Laboratory of Petroleum Engineering, Faculty of Petroleum

Engineering, China University of PetroleumBeijing, Beijing, China2Research Center of Post-doctor, Liaohe Oilfield, CNPC, Panjin,

Liaoning, China

Abstract Steam stimulation and steam flooding are two kinds of effective processes

of enhanced oil recovery for a heavy oil reservoir. But steam can lead to severe

and permanent formation damage due to interactions between injected fluids andreservoir rock and liquids. This article presents the laboratory studies undertaken

to evaluate the influence of fluid composition, temperature, salinity, pH, dissolutionand transformation of minerals, and asphalt deposition on formation damage during

steam injection. The degree of damage during steam injection is observed to bedependent on pH and temperature. The technology of casting samples micrographs

and scanning electron micrographs is employed to study the variations of reservoirproperties after steam injection in each experiment. The mechanisms of formation

damage and the characteristics of reservoir property variations are analyzed in heavy

oil reservoirs during steam stimulation or steam flooding. The results show that thesolubilities of rock and clay increase with increasing temperature and pH. Formationpores are blocked and plugged due to migration and precipitation of new minerals

and asphalt deposition away from the steam injection well due to temperature dropand pH reduction in reservoirs. A great deal of asphalt deposition alters formation

wettability to increase seepage resistance. Average porosity and average permeabilityincrease near the steam injection well due to the generation of earthworm holes and

steam channeling zones under the effect of high pH and elevated temperature. But alarge amount of crude oil is left in large and mid-size pores during steam injection

in heavy oil reservoirs.

Keywords asphalt deposition, formation damage, heavy oil reservoir, high temper-ature, mineral dissolution, pH, steam

1. Introduction

Steam stimulation and steam flooding are proven as two effective oil recovery techniques

widely applied to heavy oil reservoirs. But steam injection in heavy oil reservoirs results

in sharp waterrock and waterliquid reactions, which can decrease production potential

by reducing permeability and porosity (Reed, 1980; McCorriston et al., 1981; Mohnot

et al., 1984; Okoye et al., 1991; Bennion, 1999; Hongfu et al., 2002). Steam and hot water

from the steam generator often have pH values above 12 and low ionic content. Injection

of effluents from the steam generator into the reservoir causes many formation damages,

Address correspondence to Zhan-Xi Pang, MOE Key Laboratory of Petroleum Engineering,Faculty of Petroleum Engineering, China University of PetroleumBeijing, 18 Fuxue Road,Changping, Beijing 102249, China. E-mail: [email protected]

477


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478 Z.-X. Pang et al.

such as expansion and dispersion of water-sensitive clays, solubilization of silica and

clay minerals, composition variations of crude oil, and asphalt deposition. These damages

may cause reduction of permeability and porosity and wettability reversion in reservoir to

lower producing potential of petroleum (Gruesbeck and Collins, 1982; Leonataritis and

Mansoori, 1988; Okoye et al., 1990; Baudracco and Aoubouazza, 1995; Diabira et al.,

2001; Schembre and Kovscek, 2004).

Okoye et al. (1990) conducted a series of experimental research on various steam

temperatures and pH values influencing formation damage in heavy oil reservoirs. McCor-

riston and his colleagues (1981) conducted an experiment of formation damage in heavy

oil reservoirs and observed that alkaline boiler effluents irreversibly reduced the perme-

ability of cores by up to 70%, dispersed clays, and solubilized quartz grains. Reed (1981),

studied formation sandstone dissolution during steam injection in his earlier laboratory.

Krauskopf and Bird (1967) reported that quartz and other siliceous minerals had very low

solubility at room temperature, but at elevated temperatures solubility increased sharply.

Some studies found the fact that injection of water with different composition and

lower salinity than formation water could cause dispersion of particles, expansion, andtransformation of clay (Gruesbeck and Collins, 1982; Bennion and Thomas, 1992; Hajdo

and Clayton, 1994; Schembre and Kovscek, 2004; Zeng et al., 2007). Mohnot et al. (1984)

observed that alkaline chemicals could cause clay migration and swelling, leading to

permeability reduction. Vaidya (1991) studied the mechanisms responsible for the release

of fine particles. His work, at room temperature, showed that low salinity and high pH

could cause a release of fines.

A few studies in the literature addressed the formation of scales and precipitates at

the injection and production wells in steam stimulation or drive processes (Gruesbeck

and Collins, 1982; Babagagli and Al-Bemani, 2007). Amaefule et al. (1984) mentioned

briefly in their paper on fundamentals of alkaline flooding that plugging and scaling were

observed in field-test production wells.

Several researchers thought that the crude oil composition and the presence of min-

erals affected alteration of the crude oil properties, in situ formation of stable emulsions,

and rock wettability (Clark et al., 1983; Leonataritis and Mansoori, 1988; Hongfu et al.,

2002). Aqueous fluids interacted strongly with sandstones at elevated temperatures, which

produced formation damage related to dissolution and precipitation of minerals (Amaefule

et al., 1984; Pahlavan and Rafiqul, 1985). But the presence of crude oil affected the

rate and amount of this chemical interaction. Additionally, if the crude oil had small

but important amounts of organics acids, these could react with the alkaline solutions

to produce in situ surface-active compounds. These surfactants were adsorbed on rock

surfaces and changed the wettability of reservoir rocks.However, there are few studies on the interactions of temperature, salinity, pH,

plugging and migration of new minerals, asphalt deposits, and wettability reversion. The

interactions between fluid and rock surface, which are the dominant reasons for formation

damage, depend on the mineralogy of the porous medium, concentration, temperature,

and chemical composition of the fluids.

2. Experiments

2.1. Mineral Samples

The experiments are designed to validate the effects, such as temperature, pH, salinity,

dissolution and migration of minerals, asphalt deposits, and wettability reversion, on


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Steam Injection in a Heavy Oil Reservoir 479

formation damages of steam injection. The rock samples were obtained from two wells

in Henan Oilfield. The deposits of Henan heavy oil reservoir are contained in rela-

tively shallow geological formations composed largely of quartz sands with feldspars,

clay minerals, and other trace minerals. Clay minerals occur interbedded in the sand

as pore fillers and grain coatings. The depth of the wells is about 200300 m. The

samples from the wells were observed by thin section scanning electron microscope

analysis to study the variations of reservoir properties after steam injection. Dissolution

of rock grains and clay minerals occurred due to waterrock reaction when a large

amount of steam at high pressure and elevated temperature were injected into heavy oil

reservoirs.

Solubility studies of rock grains were carried out in a high-pressure and elevated

temperature oven. The rock samples employed in experiments were unconsolidated oil

sands from Well G51310 in Gucheng Oilfield. The solubility of rock grains removed clays

were measured under the conditions of thermal recovery. In clay solubility experiments

clay samples were separated from rock grains according to sedimentation methods for

unconsolidated sands from Well L1819 in Jinglou Oilfield. A gram of clay minerals wasput into a sealed container at high pressure and elevated temperature to measure the

solubility of clay.

2.2. Fluid Samples

Water samples were used in experiments from heavy oil reservoirs in Henan Oilfield.

The analysis of formation water indicates that it contains high concentration bicarbonate,

which is incompatible with the effluents from steam generator. Salinity of formation water

was from 2,000 to 8,000 mg/L. The cations were mainly KC and NaC, but the contents

of Ca2C and Mg2C were low in formation water. Cl and HCO3

were the primary anions

but SO24 and CO23 were relatively poor in formation water.

Steam injection can cause variations of petroleum compositions, such as light hy-

drocarbon reduction, heavy hydrocarbon addition, paraffin wax scales, and asphalt pre-

cipitation, to plug production wells. Fluorescence analysis of oil components was carried

out to compare oil samples from steam swept formations with oil samples from steam

unswept ones in order to study variations of petroleum compositions after injection

steam. The oil samples were dead oil obtained from Well G51310 of Gucheng Oilfield

in Henan.

2.3. Experimental Setup and ProcedureSome experiments were carried out in a high pressure and temperature oven to analyze

solubility of rock grains and clay minerals. A schematic diagram of the oven is shown

in Figure 1. The oven can simulate thermal conditions of elevated temperature (350C)

and high pressure (10 MPa).

Scanning electron micrographs and a petrographic study of rock and clay minerals

before and after experiments were made. A thin section of each sample was dried

and then coated with a thin layer of aluminum. Scanning electron microscopy was

then performed to observe pore geometry, crystal morphology, and asphalt deposition

under high magnification. X-ray diffraction analysis of rock and clay minerals and oil

content was also performed on some samples after injecting high-temperature steam toobtain some qualitative information on mineral or oil distributions. The laws of clay

transformation are summarized according to the analysis of experimental results.


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Figure 1. The schematic diagram of solubility experiment.

3. Results

3.1. Dissolution of Rock Grains

In order to evaluate dissolution of rock grains during high-pH steam injection, nine

experiments involving different pH solutions were conducted at 100C, 200C, and

300

C. The experimental pressure was maintained at 6 MPa in the high-pressure andtemperature oven. Each experiment was carried out for 48 hr for a certain temperature

and pH under 6 MPa. Experimental results in Table 1 show that solubility of rock grains

gradually increases with increasing pH of solution at a certain temperature and the same

results are seen for increasing temperature at a certain pH. A liter of solution with pH 13.0

can dissolve 11,580-mg rock grains at 300C, but the solution of pH 8.0 only dissolves

Table 1

Solubility of unconsolidated rock grains at different temperature and pH

Core

sample

Pressure,

MPa

Temperature,C

pH ofpre-

experiment

Time,

hr

Solubility,

mg/L

pH ofpost-

experiment

G-100-8 6 100 8.0 48 913 7.5

G-100-10 6 100 10.0 48 823 9.5

G-100-13 6 100 13.0 48 1,333 12.0

G-200-8 6 200 8.0 48 2,157 7.5

G-200-10 6 200 10.0 48 1,270 9.5

G-200-13 6 200 13.0 48 12,660 12.0

G-300-8 6 300 8.0 48 1,893 7.5

G-300-10 6 300 10.0 48 880 9.5G-300-13 6 300 13.0 48 11,580 12.0


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913-mg rock grains at 100C. The injected water (100C) with pH 8.0 would dissolve

only 7.9% of rock grains as injected water (300C) with pH 13.0. Therefore, high pH

causes a great amount of rock minerals dissolution and subsequent precipitation of new

particles away from the steam injection well in reservoirs. The experimental results show

that the pH of injected steam should be maintained at about 9. Rock dissolution seriously

changes reservoir properties and pore structures to produce sharp formation damage. The

phenomena of rock dissolution mainly occurs near the wellbore of steam injection, so

formation rock becomes more unconsolidated at elevated temperature and high pH to

result in sand production and even formation collapse. Meanwhile, dissolved minerals

will crystallize new grains or combine with other components to form new minerals away

from the steam injection well due to the reduction of temperature and pH in formation.

3.2. Dissolution of Clay Minerals

Solubility of clay minerals was measured in order to evaluate the influence of temperature

and pH on dissolution of clay. The pressure was maintained 6 MPa in the oven. Thetemperature was respectively controlled at 150C, 200C, 250C, and 300C. Solution

pH was respectively maintained ay 8.0, 9.0, 10.0, 11.0, and 13.0 in each experiment. Sol-

ubility of clay minerals gradually increased with increasing solution pH and temperature

as shown in Figure 2. The maximal solubility was 5,383.8 mg/L at pH 13.0 and 300C

and the minimal solubility was only 1,886.7 mg/L at pH 8.0 and 150C. Composition

analysis shows that the main component was SiO2 in solution, accounting for 76.1% of

total soluble amount, and the other components were, respectively, CaO, K2O, Al2O3,

FeO, and MgO in solution, accounting for less than 10%. This indicates that increasing

temperature and alkali concentration generally increase the dissolution process, whereas

the precipitation of mineral crystals will be accelerated at low temperatures and pH,

leading to plugging pore-throats away from the steam injection well.

3.3. Transformation of Clay Minerals

3.3.1. Transformation of Illite. Illite is a kind of stable mineral in reservoirs. Illite is not

easily dissolved in water and it is difficult to transform to the other minerals, especially in

enriched NaC solution when the temperature is less than 250C. But if the temperature is

Figure 2. The effect of temperature and pH on solubility of clay minerals.


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more than 250C and the pH of solution with enriched NaC or KC is more than 11, then

solubility of feldspar increases to make a lot of magnalite transform to illite at elevated

temperature under strong alkaline conditions.

magnaliteC KC ! illite=magnalite mixed layer ! illite

The content of potassium feldspar is basically constant in formation. But illite

gradually transforms to magnalite at low temperature in poor alkaline solutions that

contain enough NaC, Ca2C, and Mg2C but lack KC.

illiteC NaC.Ca2C=Mg2C/C SiO2 CH2O ! magnaliteCKC

3.3.2. Transformation of Kaolinite. Kaolinite is very unstable in strong alkaline solu-

tion. In general, kaolinite begins to dissolve in water at 150C and pH of 11 and it

entirely dissolves when temperature is above 250C and pH is over 11.

NaC.Ca2C/C kaoliniteCH4SiO4 ! magnaliteC H2OCHC

3.3.3. Transformation of Magnalite. In addition, magnalite is not stable at high pH and

elevated temperature. Magnalite will transform to illite at 350C in solution of KOH and

KHCO3 with pH above 11. X-ray diffraction analysis shows that after steam injection

magnalite disappears and the content of illite obviously increases in Well Loujian 1.

3.4. Generation of Neogenic Minerals

Scanning electron micrographs for various high temperatures show the production of

cubicites as shown in Figure 3. When temperature is above 200

C, cubicite begins togenerate in the experiments. The grain size of cubicite is about 1020 m. The amount

of generated cubicite is 4.48.2% in pH range of 810, but the amount increases to 24%

if pH goes to 13. Therefore, rock is greatly dissolved near the steam injection well where

a large amount of zeolite minerals generate due to injected steam of high pH and elevated

temperature.

Magnalite transforms to kaolinite in acidic solution but can transform to illite in

enriched KC alkaline solution. When NaC concentration is high enough in solution,

magnalite absorbs NaC to present strong expansibility in formation. Therefore, if NaC is

enriched in the reservoir during steam injection, then Ca2C and Mg2C in magnalite are

easily replaced by NaC to increase the degree of formation damage.

3.5. Scales and Precipitations of Minerals

The feed water into the steam generator is alkalescent (pH of 7.84), but the effluents from

the steam generator are strongly caustic (pH of 11.42). After the effluents are injected into

formation, the pH gradually decreases as the cycles of steam stimulation increase. The

effluents tend to neutral or alkalescent fluid finally as listed in Table 2. Those processes

show that the effluents of high pH are injected into formation to trigger violent water

rock and waterliquid reactions. Waterrock reactions make quartz, feldspar, and the other

minerals be dissolved in water. Waterliquid reactions prompt a great amount of anions

and cations to combine new minerals in formation. During thermal recovery in heavy oilreservoirs, a great deal of alkalic steam and hot water are injected into formation and they

contact rock and fluid in reservoirs to seriously decrease seepage ability of formation.


8/18


Figure 3. Scanning electron micrographs of neogenic minerals.

The depositions of CaCO3 lead to plug the narrow pores or pore-throats due to the

reactions between injection fluid and reservoir minerals during injection steam. Because

injection fluid contains Co23 and reservoir minerals contains enough Ca2C.

3.6. Deposition and Cementation of Asphalt

In order to analyze the mechanisms of formation damage from deposition and cementation

of asphalt during steam injection, scanning electron micrographs were taken to observethe thin section micrographs of asphalt in solution and the casting sample micrographs

of asphalt in pores at high temperatures.


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Table 2

The analysis of feed water, effluents, and production water

Position of sampling

CompositionInlet of steam

generatorOutlet of steam

generatorWell

11119Well1723

pH 7.84 11.42 8.45 7.21

NaC 80.00 155.00 369.00 1,238.00

KC 7.60 11.70 16.50 60.50

CaC 1.00 0.00 1.50 26.00

Mg2 0.50 0.00 0.50 6.00

Al3C 0.08 0.56 1.60 3.40

Cl 37.00 64.00 469.00 1,751.00

SO24 19.60 43.00 46.00 28.00

HCO3 149.00 0.00 137.00 506.00CO23 0.00 58.90 13.00 0.00

OH 0.00 44.00 0.00 0.00

SiO2 0.90 2.00 15.00 6.50

CO2 2.55 0.00 0.00 8.10

Suspended particles 0.10 0.10 248.50 95.00

Filtered solids 298.10 386.00 1,104.90 3,269.50

Total amount of

residuals

299.00 387.50 1,353.50 3,694.90

Total salinity 296.01 380.01 1,070.35 3,626.10

Steam injection produces hydrothermal reactions to result in a large amount of

separated asphalt particles connecting each other in liquid phase. Separated asphalt

deposition generates serious damage for petroleum production during injection steam due

to asphalt depositing to plug the formation, resulting in productivity declining greatly. In

general, asphalt in solution is in three basic types as shown in Figure 4.

1. Separated asphalt of 110 m in diameter, which are some scattered pelletoidal

particles in solution.

2. Flocculent asphalt, which has strong cohesive force to combine with many separated

asphalt particles and can freely flow in formations of film, micelle, and sponge in

solution.

3. Block asphalt above 10100m in diameter, which combines many separated asphalt

particles together to present irregular shapes, such as branch, net, block, to pack rock

grains.

Asphalt particles can precipitate on the surface of pores to plug pore-throats and

even reverse wettability of rock surface in reservoirs. Some tests of thin casting sample

were conducted at various temperatures in order to observe the characteristics of asphalt

deposition in pores. Irreducible oil in cores is dissolved by benzene solution. The residual

matters are only asphalt and colloid in pores. A thin section of each sample was driedand then coated with a thin layer of metal. Microphotographs of asphalt in pores were

taken to observe its distributions under high magnification as shown in Figure 5. The


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Figure 4. Asphalt distribution in solution at different temperatures.

results show that asphalt is present in three basic types in cores as follows:

1. Point distribution asphalt mainly generated at 50C100C, which damages reservoir

properties slightly due to its dispersion and low quantity in pores.

2. Patch distribution asphalt mainly generating at 150C200C, which damages reser-

voir properties heavily due to some larger block and flake asphalt associating with

point asphalt to plug narrow pore-throats in cores.

3. Net distribution asphalt mainly generating at 250C300C, which damages reservoir

properties variously due to continuous distribution of large block asphalt plugging

pore-throat and packing rock grains to cause wettability reversal.

Asphalt cementation in solution and asphalt adsorption on pore surface generate

complex asphalt deposition to largely damage formation. The damage reasons from


11/18


Figure 5. Asphalt deposition of thin casting sample micrographs in pores.

asphalt deposition mainly include asphalt plugging narrow pore-throats, asphalt attaching

to rock surface causing wettability reversal, water-in-oil emulsion generation increasing

seepage resistance.

3.7. Composition Variation of Oil

The study is based on the determination of the effects of high-temperature steam on

composition variation of heavy oil in formations during steam injection. The results

of composition variation in steam unswept region and swept formation in Well J503

are listed in Table 3. It can be seen from the experimental results that the content oflight hydrocarbon obviously decreases but the content of heavy hydrocarbon and asphalt

largely increases in steam swept formation during steam injection.


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Table 3

The analysis of petroleum compositions

Component content, %

Wellname

Depth,m

Formationconditions

Saturatedhydrocarbon

Aromatichydrocarbon Nonhydrocarbon Asphaltenes

J503 279.0284.0 Unswept 50.46 15.51 25.00 5.79

J503 284.0288.05 Swept 32.47 12.69 21.94 23.66

4. Discussion of Results

4.1. Variation of Porosity Near Steam Injection Well

In initial reservoir or steam unswept formation, there are the following four basic pore

types:

1. Intergranular pores of 100300m in diameter, which are the main storage space of

heavy oil occupying 6070% of the whole pore volume in reservoirs.

2. Corrosion pores with irregular shapes, which include intergranular corrosion pore, in-

traparticle corrosion pore, and intergranular corrosion fracture resulting from selective

corrosion of minerals occupying 1015% of whole pore volume in reservoirs.

3. Few microfractures, which are important to interconnect different pores resulting from

rock grains breakage and intergranular slippage.

4. Micropores less than 2m in diameter, which widely distribute in clay minerals andother trace minerals.

A kind of new pore called an earthworm hole was generated through interactions

of steam and minerals. The holes are well communicated, clean, wide, winding, and

long in steam swept formations. They can be directly observed by the scanning electron

micrographs of steam swept cores in Well J301, Well J503, and Well Loujian 1 as shown

in Figure 6. After a great amount of steam of elevated temperature, high pressure, and

high pH is injected into heavy oil reservoirs, earthworm holes are generated by three

combined actions. The actions respectively are shown as follows:

1. Strong flooding by steam at elevated temperature and high pressure.

2. Dissolution of rock grains by high pH of alkaline solution.

3. Entrainment of unconsolidated particles by heavy oil during steam stimulation.

Once the earthworm holes connect with each other among wells during steam

stimulation, serious steam channeling will happen. The main reason for frequent steam

channeling is from the communication of earthworm holes in reservoir during multicycles

of steam stimulation.

The diagrams of porosity distribution frequency of preinjection steam and postinjec-

tion steam are shown in Figures 7 and 8. Figure 7 shows that the maximal porosities are

around 36 and 38% in the initial reservoir; after steam injection the maximal porosities

are around 40 and 42% near the steam injection well as shown in Figure 8. Therefore,reservoir porosity gradually increases after steam stimulation near the steam injection

well.


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Figure 6. Pore types of scanning electron micrographs.

4.2. Variation of Permeability Near the Steam Injection Well

Permeability distributions of preinjection steam are shown in Figure 9. The results show

that the distributions of permeability present two main peak values, such as 0.40.8 and

1.62.0m2, before steam is injected into the reservoir. Figure 10 describes permeabilitydistributions of postinjection steam. The distributions of permeability present multipeak

values, but the top distribution frequency corresponding to 0.40.8 m2 decreases from

51% of preinjection steam to 22% of postinjection steam. The second distribution fre-

quency obviously moves from 1.62.0 m2 of preinjection steam to 2.83.0 m2 of

postinjection steam. Meanwhile, many other peak values are more than 2.0 m2 after

steam injection. The two figures show that permeability variations lead to the generation

of large pores and channeling fractures due to fine migration, rock grain dissolution, and

clay mineral dissolution and transformation during steam injection.

4.3. Variation of Oil Saturation during Steam Injection

Figure 11 presents thin section micrographs that show general views of pore distribution


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Figure 7. The distribution frequency of porosity in the initial reservoir.

and oil content in steam unswept and swept formations. Thin section analysis gives the

relationships between pore size and oil content as shown in Table 4.

1. The quantity of large pores (diameters more than 100m) is low but the oil content

is over 90%. Large pores containing oil decrease 4.910.7% comparing steam swept

formations with in unswept formations. So a large amount of heavy oil is recovered

from these pores by steam.

2. The quantity of middle pores (diameters between from 20 to 100 m) decreases 4.4

7.5% in steam swept formations. But heavy oil content in these pores is less than

10%.

3. Small pores (diameters less than 20m) are greatest in formation but their oil content

is less than 1%.

Figure 8. The distribution frequency of porosity in steam swept formation.


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Figure 9. The distribution frequency of permeability in the initial reservoir.

4.4. Mechanisms on Formation Damage of Steam Injection

The primary mechanisms of formation damages of steam injection include clay expansion,

mineral transformation, migration and precipitation of particles,asphalt deposition, and wet-

tability reversion. Based on the experiments the following mechanisms can be summarized:

1. Hydrating expansion of clay minerals leads to reduction of porosity and permeability

to increase seepage resistance of reservoir fluids.

2. Dissolution and transformation of rock and clay minerals during steam injection

promote the degree of formation damage.3. The generation of earthworm holes from grain migration, precipitation, and plugging

causes serious sand production to accelerate formation damages.

4. Depositions of asphalt and heavy components in heavy oil plug pore-throats in porous

media.

5. Wettability reversion of formation during steam injection increases seepage resistance

of fluids and makes a great amount of heavy oil immobile in reservoir.

Figure 10. The distribution frequency of permeability in steam swept formations.


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Figure 11. Thin section micrographs of pore distribution and oil content.

5. Conclusions

A series of experiments were conducted to study the interactions of temperature, salinity,

pH, generation and transformation of minerals, asphalt deposition, and wettability rever-

sion. The mechanisms of formation damages are summarized based on the experimental

results and reservoir property variations. From the results reported in this article, the

following conclusions can be drawn:

1. Effluents from field steam generators usually have low salinity and high pH above

11. Elevated temperature and high pH accelerate dissolution of rock and clay, mineraltransformation near the steam injection well, scaling generation and plugging away

from the steam injection well, asphalt deposition, and variations of oil components in

reservoirs.


17/18


Table 4

The relationships between pore distribution and oil content in thin sections

Large pores

>100 m

100 m

Middle pores

>20 m

Small pores

20 m

Well

name Depth, m

Formation

conditions

Pore

quantity

Oil

content,

%

Pore

quantity

Oil

content,

%

Pore

quantity

Oil

content,

%

J503 279.0284.0 Unswept 61 97.31 122 2.67 243 0.02

284.0288.05 Swept 45 97.69 101 2.29 333 0.02

J301 180.9182.9 Unswept 62 96.32 121 3.64 260 0.04

182.9185.3 Swept 48 90.34 328 8.94 1,059 0.72

2. Dissolution of rock grains during steam injection makes formation further unconsol-

idated to cause serious sand production and reservoir collapse. Generated earthworm

pores are connected to each other to lead to serious steam channeling.

3. Condensates of the steam front are found to be incompatible with formation water

and clay minerals to produce scales and precipitation plugging pore-throat in porous

media.

4. Pore surface is generated wettability reversal from water-wetted behavior to oil-wetted

behavior due to asphalt deposition. Paraffin and asphalt deposit on pore surface or

plug narrow pores and pore-throats to cause oil production reduction. The content of

light components decreases during steam injection. Heavy components and asphaltgradually deposit and plug narrow pores or pore-throats to cause production largely

reducing or shutting well in.

5. Both porosity and permeability increase near the steam injection well. The most

remaining oil is driven from large pores and middle pores in heavy oil reservoirs.

Acknowledgments

This study was funded by the National Natural Science Foundation of China (50276040)

and Important National Science & Technology Specific Projects of China (2008ZX050090-

004-05 and 2008ZX05000-011-04).

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Documents

Characteristics of Formation Damage and Variations of Reservoir Properties During Steam Injection in Heavy Oil Reservoir