Research on oil recovery mechanisms in heavy oil reservoirs

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E. RANGEL-GERMAN, S. AKIN, L. CASTANIER SPE 54591

TABLE 1. RATES AND TIMING FOR THE CORE WITH NARROW FRACTURE

_Fluid Injected_

Time

_ (hrs) _

Flow Rate

_(cm

/min)_ _ Ports _

Water 0.0 - 4.0 2.0 Top and bottom closed,

lateral open.

Water 4.0 - 5.0 2.0 Top and bottom open,

lateral closed.

Water 5.0 - 19.8 0.5 Top and bottom open,

lateral closed.

Water 19.8 - 23.0 2.0 Top and bottom closed,

lateral open.

Decane 23.0 - 27.0 2.0 Top and bottom closed,

lateral open.

Decane 27.0 - 28.0 2.0 Top and bottom open,

lateral closed.

Decane 28.0 - 44.7 1.0 Top and bottom open,

lateral closed.

Water 44.7 - 46.0 9.99 Top and bottom closed,

lateral open.

46 Shut down everything

TABLE 2. RATES AND TIMING FOR THE CORE WITH WIDE FRACTURE

_Fluid Injected_

Time

_ (hrs) _

Flow Rate

_(cm

/min)_ _ Ports _

Water 0.0 - 5.0 2.0 Top and bottom closed,

lateral open.

5.0 - 21.0 0.0 Top and bottom closed,

lateral closed.

Water 21.0 - 22.5 2.0 Top and bottom open,

lateral closed.

Water 22.5 - 25.6 2.0 Top open, bottom closed,

and lateral closed.

25.6 - 45.0 0.0 Top and bottom closed,

lateral closed.

Decane 45.0 - 48.0 2.0 Top and bottom closed,

lateral open.

Decane 48.0 - 49.2 4.0 Top and bottom closed,

lateral open.

Decane 49.2 - 51.0 4.0 Top and bottom open,

lateral closed.

51.0 - 52.0 0.0 Top and bottom closed,

lateral closed.

Water 52.0 - 54.3 4.0 Top and bottom closed,

lateral open.

Water 54.3 - 68.8 0.5 Top and bottom closed,

lateral open.

Water 68.8 - 71.0 4.0 Top and bottom open,

lateral closed.

71 Shut down everything

SPE 54591 MULTIPHASE-FLOW PROPERTIES OF FRACTURED POROUS MEDIA

0.15, 0.02 0.15, 0.010.15, 0.010.15, 0.02 0.15, 0.02 0.15, 0.01 0.14, 0.01

0.15, 0.01 0.14, 0.020.14, 0.020.14, 0.01 0.14, 0.01 0.14, 0.02

0.13, 0.08 0.13, 0.110.14, 0.120.14, 0.11 0.14, 0.12 0.14, 0.12 0.13, 0.11

0.13, 0.09 0.14, 0.080.14, 0.080.12, 0.08 0.13, 0.08 0.13, 0.07

Narrow Fracture

Wide Fracture

0.2

0.0

Fig. 5- Porosity distribution for the experimental system.

Fig. 6- CT Saturation images for the thin fracture system after 1 hr 30 min of water injection (0.67 PV.)

Fig. 7- CT Saturation images for the wide fracture system after 1 hr 30 min of water injection (0.67 PV.)

0.98, 0.05

0.96, 0.04

0.98, 4.46

0.96, 0.04

0.98, 0.04

1.04, 3.40

0.96, 0.04

0.99, 0.05

1.04, 3.33

0.97, 0.04

0.98, 0.04

1.02, 0.35

0.96, 0.04

0.97, 0.04

1.00, 0.26

0.96, 0.04

0.97, 0.04

1.00, 0.26

0.97, 0.04

1.00, 0.22

0.97, 0.03

0.97, 0.04

0.99, 0.20

0.97, 0.04

0.98, 0.60

0.85, 0.10

0.93, 0.05

0.88, 1.25

0.16, 0.12

0.52, 0.19

0.32, 0.53

-0.01, 0.04

-0.02, 0.74

-0.01, 0.54

-0.01, 0.04

-0.02, 0.62

after 1 hr. 30 min. press. port

0.99, 0.05

0.99, 0.04

0.95, 2.27

0.98, 0.05

0.99, 0.04

0.98, 2.06

0.98, 0.05

0.99, 0.05

1.00, 0.10

0.98, 0.13

0.97, 0.04

0.99, 0.13

0.97, 0.04

0.99, 0.04

0.99, 0.11

0.99, 0.06

0.99, 0.10

0.95, 0.07

0.98, 0.04

0.97, 0.10

0.75, 0.29

0.99, 0.04

0.83, 1.09

0.64, 0.39

0.96, 0.04

0.77, 0.86

0.50, 0.41

0.93, 0.05

0.68, 0.55

0.16, 0.26

0.74, 0.15

0.41, 0.78

-0.01, 0.04

0.20, 0.19

0.09, 0.57

-0.01, 0.03

-0.01, 0.04

0.01, 0.60

after 1 hr. 30 min.

press. port

E. RANGEL-GERMAN, S. AKIN, L. CASTANIER SPE 54591

Fig. 8- CT Saturation images for the narrow fracture system after 2 hr 30 min of oil injection (1.13 PV.)

Fig. 9- CT Saturation images for the wide fracture system after 2 hr 30 min of oil injection (1.13 PV.)

Fig. 10- CT Saturation images for the wide fracture system after 16 hours of water injection (7.2 PV.)

after 2 hr. 30 min. press. port

0.02, 0.11

0.02, 0.09

0.17,10.15

-0.06, 0.13

-0.05, 0.09

-0.02, 0.92

-0.07, 0.11

-0.05, 0.10

-0.02, 0.45

0.01, 0.23

0.11, 0.23

0.10, 0.43

-0.03, 0.12

-0.01, 0.09

-0.12, 8.15

0.01, 0.12

0.00, 0.10

0.02, 4.61

-0.06, 0.18

-0.05, 0.14

-0.06, 9.22

0.02, 0.12

0.01, 0.12

0.10,14.12

0.02, 0.10

0.01, 0.09

-0.01,12.20

press. port

-0.05, 0.12

-0.03, 0.14

-0.02, 0.26

-0.06, 0.13

-0.03, 0.10

-0.04, 0.25

-0.04, 0.12

-0.03, 0.11

-0.02, 0.25

after 16 hr.

press. port

after 2 hr. 30 min. press. port

0.25, 0.11

0.32, 0.11

0.28, 3.82

0.13, 0.13

0.24, 0.12

0.08, 3.95

0.05, 0.11

0.15, 0.10

0.04, 3.19

0.06, 0.12

0.06, 0.11

0.02, 0.36

0.01, 0.09

-0.02, 0.26

0.00, 0.09

-0.02, 0.24

0.00, 0.09

0.00, 0.10

-0.03, 0.32

-0.01, 0.08

0.00, 0.09

-0.05, 0.81

0.01, 0.09

0.01, 0.10

-0.04, 2.37

0.02, 0.12

0.00, 0.11

0.02, 2.63

0.02, 0.12

0.01, 0.12

-0.03, 6.17

0.01, 0.13

0.00, 0.10

-0.10, 4.14

-0.03, 0.46

0.00, 0.10

-0.01, 0.10

SPE 54591 MULTIPHASE-FLOW PROPERTIES OF FRACTURED POROUS MEDIA

Fig. 11- CT Saturation images for the wide fracture system after 17 hours of water injection (7.7 PV.)

Fig. 12- 3-D Reconstruction for both systems for water injection.

press. port

after 17 hr.

press. port

0.22 PV (30 min)

0.67 PV (1hr. 30 min)

0.89 PV (2 hr.)

0.45 PV (1hr.)

E. RANGEL-GERMAN, S. AKIN, L. CASTANIER SPE 54591

Fig. 13- 3-D Reconstruction for both systems for oil injection.

Fig. 14- Capillary pressure curves and relative permeability curves for the fracture.

2 hr. 30 min

3 hr. 45 min

1hr. 30 min

0.2

0.4

0.6

0.8

0 0.2 0.4 0.6 0.8 1

Water saturation, fraction

Pcf, atm

Case 1

Case 2

Case 3

0.0

0.2

0.4

0.6

0.8

1.0

0.0 0.2 0.4 0.6 0.8 1.0

Water saturation, fraction

Case B

Case C

- - - Matrix

___

Fracture

Case A

SPE 54591 MULTIPHASE-FLOW PROPERTIES OF FRACTURED POROUS MEDIA

1 hr. 30 min (0.67 PV)

2 hours (0.89 PV)

1 hr. (0.45 PV)

30 min. (0.22 PV)

1 hr. 30 min (0.67 PV)

2 hours (0.89 PV)

1 hr. (0.45 PV)

30 min. (0.22 PV)

Narrow

Wide

Fig. 15- Comparison between experiments and numerical simulations for narrow and wide fracture systems for different PV

of water injection.

E. RANGEL-GERMAN, S. AKIN, L. CASTANIER SPE 54591

Fig. 16- Comparison between experiments and numerical simulations for narrow and wide fracture systems for different PV

of water injection.

1.13 PV (2 hr. 30 min)

0.67 PV (1 hr. 30 min)

1.68 PV (3 hr. 45 min)

1.3 IMBIBITION STUDIES OF LOW-PERMEABILITY POROUS MEDIA

(S. Akin and A.R. Kovscek)

This paper, SPE 54590, was presented at the 1999 SPE Western Regional Meeting held

in Anchorage, Alaska, May 26-28, 1999, and presented for publication in the Journal of

Petroleum Science and Engineering.

S. AKIN AND A. R. KOVSCEK SPE 54590

This paper was prepared for presentation at the 1999 Western Regional Meeting held in

Anchorage, Alaska, 26-27 May 1999.

This paper was selected for presentation by an SPE Program Committee following review of

information contained in an abstract submitted by the author(s). Contents of the paper, as

presented, have not been reviewed by the Society of Petroleum Engineers and are subject to

correction by the author(s). The material, as presented, does not necessarily reflect any

position of the Society of Petroleum Engineers, its officers, or members. Papers presented at

SPE meetings are subject to publication review by Editorial Committees of the Society of

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for commercial purposes without the written consent of the Society of Petroleum Engineers is

prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300

words; illustrations may not be copied. The abstract must contain conspicuous

acknowledgment of where and by whom the paper was presented. Write Librarian, SPE, P.O.

Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435.

Abstract

A systematic investigation of capillary pressure, relative

permeability, and fluid flow characteristics within diatomite (a

high porosity, low permeability, siliceous rock) is reported.

Using an X-ray computerized tomography (CT) scanner, and a

specially constructed imbibition cell, we study spontaneous

cocurrent water imbibition into diatomite samples at various

initial water saturations. Air-water and oil-water systems are

used. Despite a marked difference in rock properties between

diatomite and sandstone, including permeability and porosity,

we find similar trends in saturation profiles and dimensionless

weight gain versus time functions. Diatomite is roughly 100

times less permeable than sandstone, yet it imbibes water at

rates rivaling sandstone. Importantly, the spontaneous

imbibition data when combined with CT-scan images provides

a means to determine dynamic relative permeability and

capillary pressure functions.

Introduction:

Spontaneous imbibition is perhaps the most important

phenomenon in oil recovery from fractured reservoirs. In

imbibition, capillary suction draws wetting liquid into the rock

matrix. In fractured systems, the rate of mass transfer between

the rock matrix and fractures usually determines the oil

production

1,2

. Imbibition is also essential in evaluation of

rock wettability

. Because of strong capillary forces, the

smallest pore bodies next to the fracture are usually invaded

first. The rate of imbibition is a function of porous media and

fluid properties such as absolute and relative permeability,

viscosity, interfacial tension, and wettability

. Most

experimental work on imbibition behavior has concentrated on

the scaling aspects of the process in order to estimate oil

recovery from reservoir matrix blocks that have shapes, and

sizes different from those of laboratory core samples

4-6

Two different approaches are used, typically, to model

imbibition behavior. The first approach employs a sugar-cube

type matrix-fracture system proposed by Warren and Root

where the communication occurs at the matrix-fracture

interface

. The second approach is based on a representative

elemental volume averaged fracture-matrix system

6-8

. Both

approaches use empirically determined mass transfer

functions.

Kazemi et al.

presented numerical and analytical solutions

of oil recovery using empirical, exponential transfer functions

based on the data given by Aronofsky et al.

and Mattax and

Kyte

. They proposed a shape factor that included the effect

of size, shape, and boundary conditions of the matrix. Later,

this shape factor was generalized by Ma et al.

to account for

the effect of viscosity ratio, sample shape, and boundary

conditions. The following equation was proposed:

= t

(1)

where

=µ

(2)

The above scaling equation was used by Zhang et al.

who

report that ultimate oil recovery on a pore volume basis by

spontaneous imbibition in Berea sandstone cores is

approximately constant for systems with differing lengths,

viscosity ratios, and boundary conditions.

To date, much of the focus on imbibition has centered on

carbonaceous rocks as a result of the importance of the North

Sea Chalks

12-15

, the West Texas Carbonates, and the Middle

Eastern Limestones. An important, yet relatively unstudied,

low permeability, reservoir rock for which imbibition is

believed to be an important recovery mechanism is diatomite

. Imbibition phenomena are also important during steam

injection into diatomite because steam condenses upon

injection into a cool reservoir, and the hot condensate imbibes

into the formation.

SPE 54590

Imbibition Studies of Low-Permeability Porous Media

S. Akin, Middle East Technical University and A. R. Kovscek, Stanford U., SPE Members

SPE 54590 IMBIBITION STUDIES OF LOW PERMEABILITY POROUS MEDIA

Diatomites are high porosity (>50%), low permeability

(0.1-10md)

rocks of a hydrous form of silica or opal

composed of the remains of microscopic shells of diatoms,

which are single-celled aquatic plankton

. Diatomite reservoir

rock is assumed to be moderately to strongly water wet

Estimates of the original oil in place (OOIP) for diatomite

reservoirs in California range from 10 to 15 billion barrels

and primary recovery has been estimated to be about 5% of the

OOIP

. Primary recovery is low despite hydraulically

fractured wells that improve injectivity and productivity.

Because of the high porosity, large initial oil saturation (35 to

70%), and large OOIP, the target for potential production is

high.

Multiphase flow in diatomite is assumed to be dominated

by capillary forces, but we lack a good understanding of fluid

flow and capillary pressure behavior in the rock matrix.

Compounding problems, there are only a few reported

capillary pressure curves

and little information on the extent

and rate of imbibition

. The mechanisms of oil displacement

and trapping are unclear, but assumed to be similar to those in

sandstone. However, rock morphology is very different

This study presents basic core analysis data and

experimental results of spontaneous water imbibition in

diatomite and sandstone. A state of the art experimental

imbibition cell is employed along with computed tomography

(CT) scanning to quantify the saturation distribution along the

core. It is found that the imbibition data scales according to

the equation proposed by Ma et al.

. The major focus of this

article is estimation of relative permeability and capillary

pressure from the experimental saturation data using a

nonlinear history-matching technique.

Experimental Details

Liquids

For water-air imbibition experiments, de-aerated water and air

were used, whereas for water-oil imbibition, n-decane and de-

aerated water were used. Properties of the experimental fluids

are given in Table 1.

Porous Media

Diatomite cores were cut in a direction parallel to the bedding

plane from a block of outcrop diatomite sample (Grefco

Quarry, Lompoc, CA). This sample is fairly homogeneous, but

there are regions of higher density and correspondingly lower

porosity. Figure 1 displays porosity images of the cores used

in this study. The procedure to obtain these images will be

presented, shortly. The average porosity of the samples was

slightly greater than 65% and porosity varied by about 2 to

4%. The liquid permeability varied from 6 to 9 md. Table 2

lists exact values for each core. It should be noted that because

of the brittle nature of the diatomite, the cores were machined

instead of drilled using conventional core bits as described by

Schembre et al.

. The lengths (3.45 in. or 8.763 cm) and

diameters (0.95 in. or 2.413 cm) of the cores were all close to

constant. Cores were potted with epoxy in 1 inch (2.54 cm)

Plexiglas tubes. Both ends are left open to enable cocurrent

imbibition.

Experimental Setup

The experimental setup is designed specifically for CT

measurements. It consists of three main parts: (i) a potted

diatomite core inside a (ii) water jacket and (iii) a data

acquisition system based on a personal computer, as shown in

Figure 2. Two end caps hold the imbibition cell in position

within the cylindrical water jacket. The end caps are machined

with spider-web-shaped fluid distribution grooves where the

end cap contacts the core. The entire assembly is placed inside

the CT gantry. Fluid is circulated through the jacket to

maintain a constant temperature up to 90°C (194°F) using a

heating circulator bath. The experiments reported here were

conducted at 20 °C (68 °F). The main function of the water

jacket is to reduce effects of beam hardening. Beam hardening

is the change of overall X-ray attenuation with distance into

the object. It occurs when a polychromatic X-ray beam passes

through a material that preferentially absorbs lower energy

photons. The remaining beam becomes more and more

chromatic at higher energy levels and the beam becomes

“harder”. The effects of this phenomenon are usually more

pronounced at the boundaries where there is a high density

contrast (i.e. air and core).

Three polyethylene lines (input, output, and bypass) allow

the imbibing fluid to enter the imbibition cell and the produced

fluid to exit the cell. The bypass line is used to flush any non-

wetting fluid from the lines, thus allowing the imbibing fluid to

fill the inlet end plate and easily contact the core face. The

amount of water imbibed is found by measuring the weight

loss of the water reservoir using an electronic balance

connected to a personal computer. The CT-Scanner used in

this study is a fourth generation Picker 1200-SX scanner

with 1200 fixed detectors. It allows rapid scanning on a single

vertical volume section in the center of the core as a function

of time. The acquisition time of one CT image is 3 seconds,

whereas the processing time is around 40 seconds. The total

time of measurement is selected such that it is short enough to

capture accurately the position of the imbibition front, yet it is

large enough to provide necessary X-ray energy. Table 3

gives CT scan parameters used in this study.

Imbibition Measurements

For water-air imbibition experiments, the core samples

were dried in a vacuum oven at approximately 70°C (158°F)

for 24 hours before starting the experiments. After pressure

testing for leaks, the imbibition cell is placed into the water

jacket either horizontally or vertically and the jacket is filled

with water. All experiments reported here are in the horizontal

mode. Next, the setup is placed inside the gantry and

positioned such that the main scanning plane is at the center of

the core sample and there is nothing around the setup (i.e. the

patient couch is not in the scanning plane). A reference dry

CT image is obtained using the parameters given in Table 3.