hisham abass

Transcription

hisham abass

Winter 2014
Saudi Aramco
A quarterly publication of the Saudi Arabian Oil Company
Contents
Shale Gas Characterization and Property Determination
by Digital Rock Physics
2
Anas M. Al-Marzouq, Dr. Tariq M. Al-Ghamdi, Safouh Koronfol,
Dr. Moustafa R. Dernaika and Dr. Joel D. Walls
Chemically Induced Pressure Pulse: A Novel Fracturing
Technology for Unconventional Reservoirs
14
Ayman R. Al-Nakhli, Dr. Hazim H. Abass, Mirajuddin R. Khan,
Victor V. Hilab, Ahmed N. Rizq and Ahmed S. Al-Otaibi
Integrating Intelligent Field Data into Simulation Model
History Matching Process
25
Bevan B. Yuen, Dr. Olugbenga A. Olukoko and Dr. Joseph Ansah
Borehole Casing Sources for Electromagnetic Imaging
of Deep Formations
34
Dr. Alberto F. Marsala, Dr. Andrew D. Hibbs and
Prof. Frank Morrison
Laboratory Study on Polymers for Chemical Flooding in
Carbonate Reservoirs
41
Dr. Ming Han, Alhasan B. Fuseni, Badr H. Zahrani and
Dr. Jinxun Wang
Sweet Spot Identification and Optimum Well Planning:
An Integrated Workflow to Improve the Sweep in a
Sector of a Giant Carbonate Mature Oil Reservoir
52
Dr. Ahmed H. Alhuthali, Abdullah I. Al-Sada, Abdullah A. Al-Safi
and Mohamed T. Bouaouaja
Innovation in Approach and Downhole Equipment
Design Presents New Capabilities for Multistage
Stimulation Technology
61
Mohammed A. Al-Ghazal, Saad M. Al-Driweesh, Mustafa R. Al-Zaid
and Fadel A. Al-Ghurairi
Deploying Global Competition by Innovation Network
for Empowering Entrepreneurship, Venturing and Local
Business Development: A Case Study — Desalination
Using Renewable Energy
Dr. M. Rashid Khan
70
Journal of Technology
THE SAUDI ARAMCO JOURNAL OF TECHNOLOGY
Shale Gas Characterization and
Property Determination by Digital
Rock Physics
Authors: Anas M. Al-Marzouq, Dr. Tariq M. Al-Ghamdi, Safouh Koronfol, Dr. Moustafa R. Dernaika and
Dr. Joel D. Walls
ABSTRACT
Unconventional shale reservoirs differ largely from conventional
sandstone and carbonate reservoirs in their origin, geologic
evolution and current occurrence. Shale comprises a wide variety
of rocks that are composed of extremely fine-grained particles
with very small porosity values on the order of a few porosity
units and very low permeability values in the nanodarcy (nD)
range. Shale formations are very complex at the core scale:
they exhibit large vertical variations in lithology and total organic carbon (TOC) at a scale so small that it renders core
characterization and sweet spot detection very challenging.
Shale formations are also very complex at the nano-scale level,
where pores having different porosity types are detected within
the kerogen volume. These complexities have led to further
research and the development of an advanced application of
high resolution X-ray computed tomography (XCT) scanning
on full-diameter core sections to characterize shale mineralogy,
porosity and rock facies so that accurate evaluation of the
sweet spot locations can be made for further detailed petrophysical and petrographic studies.
In this work, argillaceous shale gas cores were imaged using
high resolution dual-energy XCT scanning. This imaging technique produces continuous whole core scans at 0.5 mm spacing
and derives accurate bulk density (BD) and effective atomic
number (Zeff) logs along the core intervals, logs that are crucial
in determining lithology, porosity and rock facies. Additionally,
integrated X-ray diffraction (XRD) data and energy dispersive
spectroscopy (EDS) analysis results were acquired to confirm
the mineral framework composition of the core. Smaller core
plugs and subsamples representing the main variations in the
core then were extracted for much higher resolution XCT
scanning and scanning electron microscopy (SEM) analysis.
Porosity, mainly found in organic matter, was determined from
2D and 3D SEM images by the image segmentation process.
Horizontal fluid flow was only possible through the organic
matter and the simulations of 3D focused ion beam (FIB)-SEM
volumes by solving the Stokes equation using the Lattice Boltzmann method (LBM).
A clear trend was observed between porosity and permeability, correlating with identified facies in the core. Silica-rich facies
gave higher porosity-permeability relationship characteristics
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SAUDI ARAMCO JOURNAL OF TECHNOLOGY
compared to the clay-rich facies. This is mainly caused by the
pressure compaction effect on the soft clay-rich samples. High
percentages of organic matter were not found to be a good indication for high porosity or permeability in the clay-rich shale
samples, while the depositional facies was found to have a great
effect on the pore types, rock fabric and reservoir properties.
The results and interpretations in this study provide further
insights and enhance our understanding of the heterogeneity of
the organic-rich shale reservoir rock.
INTRODUCTION
Hydrocarbon recovery factors from unconventional organicrich shale have always been at the lower end of historic figures
from conventional reservoirs1. The reason for this is the ultralow permeability of the rock, which requires massive hydraulic
fracturing to enhance connectivity, and therefore, permeability
for the flow. The fracturing technique should have the potential to lead to economical hydrocarbon production by creating
a complex fracture network that is made up of many interconnected fractures in close proximity to one another. To choose
the right fracturing technique, one must have a good understanding of the reservoir characteristics at multiple scales. The
evaluation of shale, however, is complicated by the structurally
heterogeneous nature of the fine-grained strata and their intricate pore networks, which are interdependent on many geologic factors, including total organic carbon (TOC) content,
mineralogy, maturity and grain size.
In this work, full-diameter whole core samples from a shale
gas reservoir in the Middle East were characterized at the core
and pore scale levels. The core samples were analyzed using
the dual-energy X-ray computed tomography (XCT) scanning
technique to locate potentially high quality rock intervals with
high porosity and high TOC. Data acquired from 2D scanning
electron microscopy (SEM) and 3D focused ion beam (FIB)SEM analysis were studied to characterize the kerogen content
in the samples, together with (organic and inorganic) porosity
and rock fabric. The mineral framework of the samples was
determined from energy dispersive spectroscopy (EDS) analysis. The FIB-SEM images in 3D were used to determine porosity and TOC by segmentation and to determine directional
permeability by the Lattice Boltzmann method (LBM). Trends
were obtained among the computed data, in addition to the
TOC and rock fabric values that are necessary for proper shale
evaluation and completion considerations.
A clear trend was observed between porosity and permeability in relation to identified facies in the core. Silica-rich facies
gave higher poroperm characteristics compared to the clay-rich
facies. The depositional facies was found to have a profound
effect on the pore types, rock fabric and reservoir properties.
DUAL-ENERGY COMPUTED TOMOGRAPHY IMAGING
XCT imaging is a powerful nondestructive technique used in
the oil industry to evaluate the internal structures of cores. The
acquisition of high resolution continuous images along the
core length is essential in complex reservoirs to characterize
reservoir heterogeneity and optimize sample selection for further detailed analysis. Dual-energy computed tomography
(CT) scanning involves imaging the core at two energy levels at
the same location. This dual-energy imaging provides two distinct 3D images of the core by using a high and a low energy
setting. The high energy images are slightly more sensitive to
bulk density (BD) — Compton scattering effect — and the low
energy images are slightly more sensitive to mineralogy —
photoelectric absorption effect2. The high resolution computed
BD values and effective atomic number (Zeff), or photoelectric
factor (PEF), values can be used in shale formations to interpret and quantify porosity, organic content (for identifying
sweet spots) and mineralogy. When combined with other commonly available information, such as core spectral gamma
data, more complex analyses can be performed. For example,
the elastic properties and brittleness index can be determined3.
Recently, the technique has been used in complex carbonate
and sandstone reservoirs in the Middle East to characterize
reservoir heterogeneity and optimize the sample selection for
special core analysis testing4-6. In cases of poor core recovery
and drilling mud invasion, it becomes more practical to correlate the CT data to density logs or photoelectric logs instead of
the natural gamma ray logs.
presented in green. In this perspective, low PEF values (around
1.8) and low BD (<2.4) would indicate silica-rich shale with
low clay content and high porosity. Five different facies were
detected and highlighted in Fig. 1b. Figure 2 plots the BD data
vs. PEF with the highlighted facies. Reference lines for the
main minerals are shown in the figure to indicate mineralogy
variations in the core. It is clear from Fig. 2 that this core contains no calcite minerals. The five different color facies were
identified as follows and summarized in Table 1:
• Green facies: Data with low density and low PEF. When
Fig. 1. Dual-energy CT data along 49 discontinuous 1 ft core sections: (a) BD,
(b) identified facies, (c) PEF, (d) PEF with reversed BD, and (e) radial crosssectional images.
CORE CHARACTERIZATION AND SAMPLE SELECTION
Dual-energy CT scanning was performed on a total of 49 ft of
core (49 discontinuous 1 ft sections) from a shale source rock
reservoir in the Middle East. The dual-energy logs in Figs. 1a
and 1c provided accurate BD and PEF data, respectively, along
core lengths that were used to characterize the core sections
and to efficiently identify sweet spots for the representative selection of plug sampling locations. Shale formations are often
composed of stacked para-sequences7 that are quite thin and
difficult to detect from well logs. This high resolution data
from the whole core therefore provides a powerful tool to define these para-sequences.
Figure 1d plots the PEF data with reversed scale BD to highlight the best quality shale intervals, with the largest gap
Fig. 2. BD vs. PEF for all dual-energy CT data. Color cutoffs were identified from
Fig. 1d to highlight variations in shale properties. Reference lines for the main
minerals are shown in the figure to indicate mineralogy variations in the core.
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Color
Facies
Porosity
Organic
Matter
Silica
Clay
Carbonate
Green
High
High
High
Low
Low
Red
Low
High
Low
High
Low
Black
Very low
Low
High
Low
Low
Blue/
Yellow
Very low
Low
Low
High
Low
(a) green facies, large green fill (low PEF, low BD)
Table 1. Potential description of each identified facies in the cores based on PEF and
BD values from dual-energy CT data
BD is reversed as in Fig. 1d, it creates the largest gap between the PEF and ROHB curves. This identifies the potential regions for silica-rich shale with high porosity/organic matter and low clay content (sweet spots). This behavior is clearly shown in one of the zoomed intervals as
represented by Fig. 3a.
• Red facies: Data with medium density and medium PEF.
When BD is reversed, it creates a small gap between the
curves. This identifies potential regions for clay-rich shale
with low porosity/high organic matter and low silica content. This behavior is clearly shown in one of the zoomed
intervals as represented by Fig. 3b.
• Black facies: Data with high density and low-to-medium
PEF. When BD is reversed, it creates no gap between the
curves. This identifies potential regions for silica-rich
shale with very low porosity/low organic matter and low
clay content. This behavior is clearly shown in one of the
zoomed intervals as represented by Fig. 3c.
• Blue/yellow facies: Data with high density and medium
PEF. When BD is reversed, it creates a large gap between
the curves filled with blue. This identifies potential regions for clay-rich shale with very low porosity/low or
ganic matter and low silica content. The larger gap in this
group indicates denser layers, which are indicated with
yellow; the layers are otherwise blue, as can be clearly
seen in the “facies” and “radial image” columns in Fig. 3d.
Table 1 provides only qualitative indications for the facies
variations in the cores and should be confirmed by further detailed analysis using X-ray diffraction (XRD), EDS and SEM.
It should also be noted that (in this analysis) each color facies
has a range of dual-energy data that allows for shale property
variations within the same facies. Therefore, the description in
Table 1 should be used only to locate potentially high quality
shale for sampling and further analysis.
Facies-based Sample Selection
Figure 4 combines wireline log data with the dual-energy XCT
derived data. In column (c) the BD data from dual-energy CT
shows a reasonable match with the wireline density log.
Column (h) shows the percentage of quartz obtained from the
XRD analysis performed in selected locations in the core to
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(b) red facies, small green fill (medium PEF, medium BD)
(c) black facies, small blue fill (medium PEF, high BD)
(d) blue/yellow facies, large blue fill (medium PEF, high BD)
Fig. 3. Example of color facies based on the dual-energy CT data from Fig. 1d.
confirm the facies distribution determined from dual-energy
CT and described in Table 1. High quartz percentages from the
XRD data confirmed the green facies in the core and the facies
description in Table 1. Similarly, column (j) shows high clay
concentrations from the XRD data for the red and yellow facies,
which are characterized by medium-to-high PEF values, thereby
confirming the descriptions in Table 1. The nine arrows in
Fig. 4. (a) wireline gamma ray, (b) total gamma, (c) wireline density vs. duel-energy density, (d) identified facies from dual-energy CT, (e) PEF from dual-energy CT, (f) PEF
with reversed BD from dual-energy CT, (g) recommended sampling locations, (h) % quartz from XRD data, (i) wireline neutron/density, (j) % clay minerals from XRD data,
(k) potassium log, (l) thorium log, and (m) uranium log. Arrows in column (g) indicate selected plug locations for further porosity, permeability and TOC characterization.
Arrow colors refer to identified facies from dual-energy CT.
Fig. 4g indicate the selected plug sampling locations in the core
for further shale characterization. Five samples were cut from
the green facies (identified sweet spot), three from the red facies and one from the yellow facies.
The goal of this facies analysis and sample selection is to explore the possible links between shale depositional facies and
pore types in shale rocks. This will enhance our understanding
of the overall reservoir quality. It is also our goal to quantify
the relationship between porosity and matrix permeability for
each identified facies in the core. Identifying such trends of
poroperm data and facies would facilitate upscaling, reserves
estimation and well-to-well correlation.
PETROPHYSICAL PROPERTIES
Laboratory-based core analysis data on shale rocks are very
difficult to obtain due to the tight nature of these rocks. Traditional laboratory evaluation methods may not be applicable to
shale, and therefore the continued development of laboratory
methods is required to help characterize and understand challenging shale reservoir behaviors. In recent years, digital imaging
technology has been extensively used in the petroleum industry, including in shale formations8, to obtain fast and reliable
core data such as porosity and permeability. The new emerging
technology has been called digital rock physics (DRP) and has
contributed reliably to the computations of reservoir properties
through image segmentation in 3D and direct simulation4, 9-11.
Micro XCT Imaging
Each selected plug sample from the nine whole cores was
scanned with a micro XCT scanner at a resolution of 40 microns per voxel. A series of multiresolution scans was then
acquired, down to 4 microns per voxel, to evaluate the microscale heterogeneity and to scout for an optimal location in the
sample for further SEM analysis. These micro XCT scans were
combined with X-ray fluorescence readings to characterize the
elemental composition of the sample and to locate a region
that could adequately represent the sample. Figure 5 presents
an example of such images from Sample #1.
2D SEM
In Fig. 5d, a representative region (outlined in red) was selected for 2D SEM overview. The 2D SEM area was extracted
and polished with a broad ion beam, resulting in a smooth surface of approximately 1,000 by 500 microns. That surface was
imaged at a resolution of approximately 250 nanometers (nm)
per pixel. Then a series of high resolution SEM images was
acquired perpendicular to the lamination at a resolution of 10
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Fig. 5. Multiresolution XCT images from whole core at (a) 500 microns/voxel down to (d) XCT at 4 microns/voxel.
Fig. 6. 2D SEM images from plug Sample #1: (e) 2D SEM overview image at 250 nm/pixel selected from the XCT image at 4 microns/pixel (d); (f) a set of 10 high
resolution 2D SEM images at 10 nm/pixel; (g) one representative high resolution 2D SEM image chosen for 3D FIB-SEM (the 3D area of interest is outlined in red).
nm per pixel. It is at this resolution that we were able to observe and quantify porosity and organic matter content. Figure
6 shows a representation of this analysis. Images were segmented for total porosity, porosity in organic matter, organic
matter and high density. These results were used to choose one
representative image with high porosity and high organic matter for 3D FIB-SEM. The segmented data for all the nine plug
samples are shown in Table 2. The identified facies from the
nine samples link very well with the segmented porosity and
organic matter percentages. As described in Table 1 from the
dual-energy CT data in the core, Table 2 shows that the green
facies has the highest porosity, the red facies has low porosity,
and the yellow facies has very low porosity. The pictures of
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selected 2D SEM images from the different facies shown in Fig.
7 confirm the obtained data in Table 2.
3D FIB-SEM
The area of interest in Fig. 6g was imaged in 3D at a resolution of 15 nm per voxel using FIB-SEM imaging and digital
reconstruction techniques. Rock matrix materials, organic
matter and porosity were individually identifiable via their
unique gray scale signatures. Each of the 3D volumes from the
plug samples was digitally analyzed, and volumetric percentages of organic matter and total porosity were determined. The
porosity was further analyzed and quantified as connected,
Plug Sample #
Core Facies
Porosity (%)
Organic Matter (%)
Porosity in Organic
Matter (%)
High Density
Material (%)
1
Red
1.58
8.16
1.33
2.06
2
Red
1.51
9.91
1.34
1.74
0.88
4.24
3
Red
1.17
16.37
4
Green
3.09
13.48
2.73
2.99
5
Green
5.36
8.75
4.05
0.57
6
Green
3.95
6.02
2.66
0.53
13.56
3.92
0.82
7
Green
4.80
8
Green
2.63
5.01
1.84
2.46
9
Yellow
0.29
0.75
0.08
0.37
Table 2. Average values from the 10 2D SEM images for each plug sample
Fig. 7. Example 2D SEM images (at 10 nm/pixel) representing different facies that were identified at core scale.
non-connected and associated with organic matter. The connected porosity was used to compute absolute permeability directly in the 3D digital rocks in the horizontal and (whenever
possible) vertical directions using the LBM12. Porosity associated with organic matter can be an indicator of organic matter
maturity and flow potential. Table 3 gives the segmented values from the 3D FIB-SEM volumes. The table also gives calculations of the conversion ratio, and the organic porosity and
total porosity in percentages. The conversion ratio percent
would represent the porosity within the organic matter with
respect to the organic matter volume, while the organic-to-total porosity percent would represent the percentage of pores in
the organic matter with respect to the total porosity in the 3D
volume. The 3D volume data in Table 3 is a clear confirmation
of the potential relationship among facies, pore type, porosity
and flow characteristics in shale. Both the red and green facies
have high percentages of organic matter, but the red facies are
at the lower range of porosity, which influenced the flow properties and thereby yielded much lower matrix permeabilities
than the green facies samples. This can be quantified in Table 3
by the conversion ratio values, which show higher than 30%
for the green facies and lower than 20% for the red facies.
These findings suggest that further analysis of the organic matter and mineral framework in the red facies samples is required
to determine the reasons behind the lower conversion ratios.
Sample #9 was excluded from the 3D FIB-SEM analysis because the sample showed no flow potential due to the very low
porosity in the 2D SEM image in Fig. 7 and Table 2.
Figure 8 shows video snapshots from the different facies with
their different permeability values. This figure serves as a good
visual means to evaluate the simulated directional permeability
values in Table 3. Sample #1 has low horizontal permeability
with low porosity in the organic matter. Sample #5 has higher
horizontal permeability and gave rise to flow in the vertical
direction as well. Sample #8 has the highest horizontal permeability value, and the reason is clearly seen to be an unrepresentative streak of organic matter with relatively large pore
sizes. The permeability in these shale facies seem to be controlled
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Core
Facies
Porosity
(%)
NonConnected
Porosity
(%)
Organic
Matter
(%)
Porosity in
Organic
Matter
(%)
Absolute
Permeability
(Kh) (nD)
Absolute
Permeability
(Kv) (nD)
Conversion
Ratio (%)
Porosity
in OM/
Total
Porosity
(%)
1
Red
2.2
0.9
14.8
2.1
40
0
12.4
95.5
2
Red
2.5
0.8
9.3
2.2
19
0
19.1
88.0
3
Red
3.2
0.8
18.5
3.0
50
0
14.0
93.8
4
Green
6.1
1.5
11.4
5.1
102
0
30.9
83.6
5
Green
5.0
0.8
7.1
4.2
131
32
37.2
84.0
6
Green
6.4
1.2
9.3
5.6
348
21
37.6
87.5
7
Green
5.3
0.6
9.2
4.9
786
0
34.8
922.5
8
Green
7.7
1.2
10.1
6.8
6,111
0
40.2
88.3
Plug
Sample
#
Table 3. Values from 3D FIB-SEM volumes for each plug sample
the EDS mineralogy results. Table 5 gives the XRD data and
confirms the EDS analysis. Figure 9 presents schematic comparisons between the EDS and XRD analyses for Sample #1 from the
red facies and Sample #6 from the green facies. EDS is represented by the mineral distribution map and XRD by the pie chart.
EFFECTS OF DEPOSITIONAL FACIES ON PORE TYPES,
ORGANIC MATTER, ROCK FABRIC AND RESERVOIR
PROPERTIES
Fig. 8. Example 3D FIB-SEM video snapshots (at 15 nm/pixel) representing
directional flow for different samples.
Shale pore systems may generally be described and classified as
inter-granular (between grains), intra-granular (within grains)
or organic matter13. Porosity within organic matter would be
formed by the shrinkage of kerogen during maturation. The
inter-granular and intra-granular pores are inorganic and so
by the organic matter distribution and the porosity associated
with the organic matter.
MINERALOGY
Areas of interest for the EDS analysis were selected to include
the analyzed 2D SEM images and the 3D area of interest. The
SEM-EDS area of interest is imaged at a resolution of approximately 200 nm per pixel and covers an area of approximately
200 by 150 microns. Table 4 gives the mineral volume percentages for all plug samples analyzed by EDS. The EDS results
confirm a clear link between mineralogy and the core facies as
analyzed from dual-energy CT data on the whole cores and as
previously described in Table 1. The red and yellow facies are
clay-rich shale with less than 25% silica, while the green facies
are silica-rich shale with less than 25% clay. One would then
be tempted to think of a link between mineralogy and porosity
when comparing the red and green facies. These two facies
have similar fractions of organic matter but different porosity.
The reason for this could be either maturation of kerogen or
the mineral framework of the samples.
XRD analysis was performed on all nine samples to confirm
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Fig. 9. Comparisons between EDS (top) and XRD (bottom) analyses for Sample #1
(red facies) and Sample #6 (green facies). EDS is represented by the mineral
distribution map and XRD by pie chart. Reference mineral phase is given for the
EDS mineral maps, and legend is given for the XRD pie charts.
Plug #
Core
Facies
PlaSilica gioclase
KFeldspar
Clay
Calcite
Dolomite
Siderite
Anhydrite
Pyrite
Rutile
Apatite
Other
Total
1
Red
13.7
5.0
0.0
72.1
1.0
0.2
0.0
0.0
4.7
0.5
0.0
2.9
100
2
Red
21.3
5.4
0.3
62.4
0.1
2.5
0.0
0.0
4.7
0.5
0.0
2.8
100
3
Red
25.6
9.8
0.0
44.5
0.0
6.1
0.0
0.0
7.6
0.8
0.2
5.5
100
4
Green
57.5
5.6
0.0
29.1
0.0
1.7
0.0
0.0
3.2
0.3
0.9
1.6
100
5
Green
64.8
2.3
0.0
18.7
0.1
3.9
0.0
0.0
1.3
0.1
0.0
8.8
100
6
Green
74.4
1.6
0.5
20.6
0.1
0.2
0.0
0.0
1.0
0.1
0.0
1.6
100
7
Green
73.0
5.0
0.0
19.1
0.1
0.0
0.0
0.0
1.3
0.4
0.0
1.1
100
8
Green
63.4
4.4
0.0
25.3
0.1
2.1
0.0
0.0
1.3
0.5
0.3
2.7
100
9
Yellow
20.2
8.3
0.0
67.0
0.0
0.0
0.0
0.0
0.5
0.5
0.3
3.1
100
Table 4. Volume percent mineralogy from EDS analysis
Sample
Core
Facies
Illite/
Smectite
Illite+
Mica
Kaolinite
Chlorite
Chert
Quartz
K
Feldspar
Plagioclase
Calcite
Dolomite
Siderite
Pyrite
Total
1
Red
19.9
31.6
15.8
11.2
0.0
10.5
TR
2.1
1.2
1.2
0.0
6.4
100
2
Red
20.2
31.9
12.1
10.0
0.0
12.7
TR
2.9
0.0
1.8
0.0
8.6
100
3
Red
23.9
27.5
0.0
3.5
0.0
21.0
TR
3.6
0.0
2.0
0.0
18.5
100
4
Green
14.8
25.4
0.0
0.2
0.0
42.0
TR
4.2
0.0
4.5
0.0
8.9
100
5
Green
0.0
15.8
0.0
0.0
0.0
76.4
TR
2.3
0.0
1.5
0.0
4.1
100
6
Green
0.4
17.3
0.0
0.0
0.0
74.7
TR
2.8
0.0
1.6
0.0
3.1
100
7
Green
0.2
20.2
0.0
2.6
0.0
69.4
TR
2.0
0.0
0.8
0.0
4.8
100
8
Green
0.2
25.1
0.0
4.0
0.0
58.9
TR
2.3
TR
3.1
2.3
4.0
100
9
Yellow
25.7
35.5
0.0
10.4
0.0
19.3
TR
3.2
0.0
0.0
5.9
0.0
100
Table 5. XRD analysis
would normally be located in the matrix. The organic matter
itself may also be classified as nonporous, spongy or pendular8.
In this study, each area of the 2D SEM produced two images: Secondary electron (SE2) micrographs that are used to
quantify porosity and organic matter, and backscattered electron (BSE) micrographs that better display the contrast between the solid components of the rock.
Red Facies
Figure 10a presents examples of such images for the red facies
— Sample #1. In this sample, in the SE2 image, the organic
matter appears to be compacted between the delicate clay mineral layers and elongated in the horizontal direction. This compaction must have led to the compaction of the pores within
the organic matter. The BSE image clearly shows the clay minerals oriented in the horizontal direction due to overborne
pressure. The pores in this facies are almost all in the organic
matter, and the porosity value of Sample #1 is around 2% with
only 1% porosity connected in the 3D FIB-SEM volume. This
has led to a very low matrix permeability of 40 nano-darcy (nD).
Green Facies
Figure 10b presents examples from the green facies — Sample
#7. In this sample, in the SE2 image, the organic matter appears
to be protected from severe pressure compaction between the
strong quartz grains and the microcrystalline silica particles.
The organic matter in this facies seems to have an irregular
shape with a spongy type of porosity at 5%. Therefore, the
pore space within the organic matter was preserved and gave
good connectivity in 3D, which yielded a very high permeability
value at 786 nD. The BSE image in Fig. 10b clearly shows the
grainy structure of the quartz particles around the organic
matter that is spread out in the whole image. The pores in this
facies are almost all in the organic matter.
The poroperm characteristics of these shale facies are plotted from the Table 3 data and are shown in Fig. 11. The green
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Fig. 12. Organic matter vs. porosity for the red and green facies: The green facies
have larger porosity but less organic matter.
for North American shale plays, the data from this Middle
East shale gas fell within the upper and lower bounds of Eagle
Ford shale in the United States. Figure 12 plots organic matter
vs. porosity, both derived from the 3D FIB-SEM volumes, and
shows that the red facies have more organic matter with lower
conversion ratios.
EFFECTS OF HETEROGENEITY
Fig. 10. Different pore types detected in different facies.
Fig. 11. Poroperm characteristics of the red and green facies with Eagle Ford upper
and lower bounds.
facies samples are at the higher poroperm range. It is interesting to note that the red facies samples have higher concentrations of the organic matter — 10% to 20% — and yet gave
lower poroperm values compared to the green facies samples
with only 7% to 11% organic matter. These organic matter
figures were derived from the 3D FIB-SEM volumes. In this
perspective, flow properties of this shale formation are controlled more by the rock fabric, the mineralogy and the resultant porosity within the organic matter.
As an initial comparison of these poroperm results to those
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Shales are heterogeneous at millimeter to centimeter scales.
Figure 13 compares the segmented porosity and organic matter
data from the 2D SEM image with those from the 3D FIBSEM volume. The figure shows that analyzed samples show
porosity variations that could be larger than those of the organic matter at different scales. Porosity estimations from the
3D volume could double the initial estimations from the 2D
SEM images.
Figure 14 serves as a visual comparison of the 2D and 3D
SEM images, where the porosity in this example (Sample #7)
decreased from 6.2% in the 2D image to 5.3% in the 3D image, and the organic matter decreased from 15.1% in the 2D
image to 9.2% in the 3D image. The average results from all
10 of the 2D SEM images from this sample were 4.8% porosity and 13.6% organic matter.
Close inspection of all 10 of the 2D SEM images acquired for
every sample in this study revealed the porosity variation —
within each set of the 10 2D SEM images — to be less than 3%
porosity unit and the organic matter variation to be less than 5%.
VALIDATION OF CORE FACIES FROM DUAL-ENERGY
XCT
The initial plug sample selection in the core was based on
accurate application of a dual-energy XCT imaging technique
that produced continuous BD and PEF data along the core
lengths. The sample selection targeted three different facies
(green, red and yellow) in the core identified from the
Fig. 13. Comparison between the data obtained from the selected 2D SEM image for 3D FIB-SEM and the 3D volume data: porosity (left) and organic matter (right) —
heterogeneity effect.
and organic matter values derived from high resolution SEM
images and through EDS and XRD analyses. Figure 15 is a
nice representation of the excellent match in porosity, mineralogy and organic matter between core facies described by dualenergy CT and by high resolution SEM images. This would
assist in more efficient upscaling, improved reserves estimation
and enhance well-to-well correlation.
CONCLUSIONS
Fig. 14. Comparison between the data obtained from the selected 2D SEM image
(left) from Sample #7 and the 3D FIB-SEM volume (right) — heterogeneity effect.
Fig. 15. Analysis of reservoir shale characteristics (porosity, mineralogy and organic
matter) from core dual-energy CT scanning and SEM.
dual-energy CT data. The shale characteristics — porosity, organic matter and mineralogy — of the selected samples from
the core facies were then confirmed through segmented porosity
Initial core facies characteristics — porosity, organic matter
and mineralogy — of a shale formation in the Middle East
were computed using the dual-energy CT scanning technique.
This core facies analysis was used to locate potential sweet
spots in the core for optimum sample selection. The selected
plugs, following a well-defined DRP workflow, underwent
multiresolution scanning to construct 3D FIB-SEM volumes
for the determination of shale porosity, organic matter and
mineralogy. The objectives of the study were to explore possible
links between shale depositional facies and pore types as well
as to quantify the relationship between porosity and matrix
permeability for each identified facies in the core. The objectives
of the study were fulfilled and the following is a summary of
the key findings in this shale play.
1. A robust dual-energy CT scanning technique was used to
characterize a shale gas core and to identify potential facies
intervals for DRP analysis.
2. Absolute shale matrix permeability was determined in horizontal and vertical directions in 3D FIB-SEM volumes.
3. Only two samples (out of eight) gave 3D connectivity in the
vertical direction for permeability simulation in the silicarich samples. This is consistent with a shale depositional
environment and anisotropy considerations.
4. Almost all the porosity was found within the organic matter
volume. Consequently, flow was only possible through
organic matter within the 3D volumes.
5. The silica-rich facies gave higher poroperm characteristics
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compared to the clay-rich facies. This is due to the pressure
compaction effect on the soft clay-rich samples, which
caused the organic matter to be squeezed within a clay mineral framework, leading to closure of the pore space.
6. A very high permeability value (6,000+ nD) was simulated
in one of the samples, which a visual examination determined was caused by an unrepresentative porous organic
matter layer along the horizontal direction. Such an observation has led to the recognition of the importance of the
visuals in explaining the petrophysical data in the samples.
7. A higher percentage of organic matter was not found to be
a good indication for high porosity or permeability in the
clay-rich shale samples in this study. The conversion ratios
of organic matter should be taken into consideration when
judging porosity or permeability.
8. A clear trend was observed between porosity and permeability in relation with the identified facies in the core.
9. The depositional facies was found to have a great effect on
the pore types, rock fabric and reservoir properties. Of particular importance are the mineralogy and clay in the samples.
10. Shale heterogeneity in this formation showed larger effects
on porosity variability than organic matter variations at
different scales.
11. The results and interpretations in this study enhanced our
understanding of the complexity of unconventional shale
reservoir quality.
NOMENCLATURE
K
Kh
Kv
Zeff
Ø
permeability
horizontal permeability
vertical permeability
effective atomic number
porosity
ACKNOWLEDGMENTS
The authors would like to thank the management of Saudi
Aramco for their support and permission to publish this article.
Ingrain Inc. conducted the measurements discussed in this article.
This article was presented at the SPE-SAS Annual Technical
Symposium and Exhibition, al-Khobar, Saudi Arabia, April 2124, 2014.
REFERENCES
1. Butler, J.A., Bryant, J.E. and Allison, D.B.: “Hydrocarbon
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SPE paper 167182, presented at the SPE Unconventional
Resources Conference-Canada, Calgary, Alberta, Canada,
November 5-7, 2013.
2. Wellington, S.L. and Vinegar, H.J.: “X-ray Computerized
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No. 8, 1987, pp. 885-898.
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3. Walls, J. and Armbruster, M.: “Shale Reservoir Evaluation
Improved by Dual-energy X-ray CT Imaging: Technology
Update,” Journal of Petroleum Technology, November
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4. Amabeoku, M.O., Al-Ghamdi, T.M., Mu, Y. and Toelke,
J.: “Evaluation and Application of Digital Rock Physics
(DRP) for Special Core Analysis in Carbonate
Formations,” IPTC paper 17132, presented at the
International Petroleum Technology Conference, Beijing,
China, March 26-28, 2013.
5. Al-Owihan, H., Al-Wadi, M., Thakur, S., Behbehani, S.,
Al-Jabari, N., Dernaika, M., et al.: “Advanced Rock
Characterization by Dual-Energy CT Imaging: A Novel
Method for Complex Reservoir Evaluation,” IPTC paper
17625, presented at the International Petroleum
Technology Conference, Doha, Qatar, January 20-22, 2014.
6. Al Mansoori, M., Dernaika, M., Singh, M., Al Dayyani, T.,
Kalam, Z. and Bhakta, R.: “Application of Digital and
Conventional Techniques to Study the Effects of
Heterogeneity on Permeability Anisotropy in a Complex
Middle East Carbonate Reservoir,” SPWLA paper,
presented at the SPWLA 55th Annual Logging Symposium,
Abu Dhabi, UAE, May 18-22, 2014.
7. Passey, Q.R., Bohacs, K.M., Esch, W.L., Klimentidis, R.
and Sinha, S.: “From Oil-Prone Source Rock to Gas
Producing Shale Reservoir — Geologic and Petrophysical
Characterization of Unconventional Shale Gas Reservoirs,”
SPE paper 131350, presented at the International Oil and
Gas Conference and Exhibition in China, Beijing, China,
June 8-10, 2010.
8. Walls, J.D. and Sinclair, S.W.: “Eagle Ford Shale Reservoir
Properties from Digital Rock Physics,” First Break, Vol.
29, No. 6, June 2011, pp. 97-101.
9. De Prisco, G., Toelke, J. and Dernaika, M.: “Computation
of Relative Permeability Functions in 3D Digital Rocks by
a Fractional Flow Approach Using the Lattice Boltzmann
Method,” SCA2012-36 paper, presented at the
International Symposium of the Society of Core Analysts,
Aberdeen, Scotland, U.K., August 27-30, 2012.
10. Mu, Y., Fang, Q., Baldwin, C., Toelke, J., Grader, A.,
Dernaika, M., et al.: “Drainage and Imbibition Capillary
Pressure Curves of Carbonate Reservoir Rocks by Digital
Rock Physics,” SCA2012-56 paper, presented at the
Aberdeen, Scotland, U.K., August 27-30, 2012.
11. Grader, A., Kalam, M.Z., Toelke, J., Mu, Y., Derzhi, N.,
Baldwin, C., et al.: “A Comparative Study of Digital
Rock Physics and Laboratory SCAL Evaluations of
Carbonate Cores,” SCA2010-24 paper, presented at the
Halifax, Nova Scotia, Canada, October 4-7, 2010.
12. Tolke, J., Baldwin, C., Mu, Y., Derzhi, N., Fang, Q.,
Grader, A., et al.: “Computer Simulations of Fluid Flow
in Sediment: From Images to Permeability,” The Leading
Edge, Vol. 29, No. 1, January 2010, pp. 68-74.
13. Loucks, R.G., Reed, R.M., Ruppel, S.C. and Hammes,
U.: “Preliminary Classification of Matrix Pores in
Mudrocks,” Gulf Coast Association of Geological
Societies Transactions, Vol. 60, April 2010, pp. 435-441.
BIOGRAPHIES
Anas M. Al-Marzouq is a Petroleum
Engineer in Saudi Aramco’s Reservoir
Description Division. He joined Saudi
Aramco in 2004 and is currently
working in the Exploration
Petrophysical Unit. Anas is a member
of the Tight Gas Assessment team, the
Unconventional Gas Petrophysical team and the Northwest
Unconventional Gas Operation team.
He has published and coauthored many papers and
journal articles. Anas’s recent work involves integration of
the core and petrophysical measurements to evaluate
unconventional gas resources.
He received his B.S. degree from King Fahd University
of Petroleum and Minerals (KFUPM), Dhahran, Saudi
Arabia, in 2004, and his M.S. degree from Texas A&M
University, College Station, TX, in 2010, both in Petroleum
Engineering.
Dr. Tariq M. Al-Ghamdi is a Reservoir
Engineer working in Saudi Aramco’s
Reservoir Description and Simulation
Department. His responsibilities
include management and petrophysical
evaluation of exploration and gas
fields. Tariq is currently leading the
Unconventional Shale
Shal Gas team in Saudi Aramco. His main
interests are optimizing petrophysical evaluation,
permeability modeling and modeling saturation height
function; recently Tariq has been involved in digital core
analysis and numerical simulations of special core analysis
and nuclear magnetic resonance. He has published and
coauthored numerous papers and journals.
Tariq received his B.S. degree from the University of
Tulsa, Tulsa, OK, his M.S. degree from Heriot-Watt
University, Edinburgh, U.K., and his Ph.D. degree from the
University of New South Wales, Kensington NSW,
Australia, all in Petroleum Engineering.
Safouh Koronfol joined Ingrain Inc. in
May 2012 and is the Operations
Manager. He has 10 years of special
core analysis experience. Safouh was
the Head of the Special Core Analysis
Department at Weatherford
Laboratories Abu Dhabi and later
became the
b
h SCAL coordinator between Weatherford Labs
globally and Shell/Petroleum Development Oman in
Muscat, Oman.
Safouh received his B.S. degree in Industrial Chemistry
from University of Aleppo, Aleppo, Syria. He is an active
member of Society of Petrophysicists and Well Log
Analysts (SPWLA), the Society of Petroleum Engineers
(SPE) and the Society of Core Analysts (SCA). Safouh has
authored and coauthored seven technical papers on both
conventional SCAL and digital rock physics.
Dr. Moustafa R. Dernaika has been
the Manager of Ingrain Inc. Abu
Dhabi since 2010. Before he joined
Ingrain, he worked for Emirates Link
ResLab LLC (Weatherford
Laboratories) as the Regional Special
Core Analysis (SCAL) Manager in Abu
Dhabi.
Dh bi He
H has
h 15 years of routine and SCAL experience
with special interest in business development, project
management and data interpretation.
Moustafa has written 26 technical papers. His current
research areas include digital rock physics, dual energy
coiled tubing applications and the variations of
petrophysical and flow properties with rock types and
wettability.
Moustafa received his B.S. and M.S. degrees in
Chemical Engineering from the Middle East Technical
University, Ankara, Turkey, and his Ph.D. degree in
Petroleum Reservoir Engineering from the University of
Stavanger, Stavanger, Norway.
Dr. Joel D. Walls is a Geophysicist
focused on research, development, and
commercialization of advanced digital
rock physics services for unconventional
reservoirs. He joined Ingrain Inc. in
2010, and as the Director of Technology,
JJoel guides the development and
commercialization of services focused on shale plays.
Joel was a co-founder and the first president of the
Society of Core Analysts (SCA). He is a member of the
Society of Economic Geologists (SEG), Society of Petroleum
Engineers (SPE) and the Society of Petrophysicists and Well
Log Analysts (SPWLA). Joel is the author of numerous
publications in several geophysical and petrophysical
journals, and holds four U.S. patents in the rock physics
and reservoir characterization.
He received his B.S. degree in Physics from Texas A&M
University, College Station, TX. Joel received his M.S. and
Ph.D. degrees in Geophysics from Stanford University,
Stanford, CA.
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13
Chemically Induced Pressure Pulse:
A Novel Fracturing Technology For
Unconventional Reservoirs
Authors: Ayman R. Al-Nakhli, Dr. Hazim H. Abass, Mirajuddin R. Khan, Victor V. Hilab, Ahmed N. Rizq and
Ahmed S. Al-Otaibi
ABSTRACT
The huge resources of unconventional gas worldwide, along
with the increasing oil demand, make the contribution of unconventional gas critical to the world economy; however, one of
the major challenges that operators face with production from
unconventional resources is finding a commercial stimulation
technique that creates sufficient stimulated reservoir volume
(SRV). Unconventional reserves trapped within very low permeability formations, such as tight gas or shale formations,
exhibit little or no production, and are therefore economically
undesirable to develop with existing conventional recovery
methods. Such reservoirs require a large fracture network with
high fracture conductivity to maximize well performance.
One commonly employed technique for stimulating low
productivity wells is multistage hydraulic fracturing, which is
costly and typically involves the injection of high viscosity fluids into the well. Fracturing fluid by itself could be a damaging
material for the fracture due to the high capillary forces involved. Therefore, the need exists for another more economical
method to enhance production within a tight gas formation.
This article discusses a new stimulation method to increase
SRV around the wellbore and fracture area, thereby improving
unconventional gas production. The method entails triggering
an exothermic chemical reaction in situ to generate heat, gas
and localized pressure sufficient to create fractures around the
wellbore. In a controlled experiment, chemical reactants were
separately injected into core samples with a mini-hole, and
upon their mixing inside the core, an exothermic chemical reaction occurred and the resultant heat and gas pressure caused
macrofractures. Nuclear magnetic resonance (NMR) porosity
imaging showed a significant increase in macropores throughout the core. Additionally, large-scale experiments using cement
blocks with a simulated wellbore cavity were performed. Once
the wellbore was filled with the chemicals and a triggering catalyst was introduced, an in situ chemical reaction took place,
which generated heat and gas with sufficient pressure to cause
shear fractures in the surrounding rock. These experiments, which
showed extensive fractured and shattered pieces, also provided
preliminary design requirements for a field test. The chemical
reactants were then incorporated into a fracturing gel that simulated additional fractures created from the main induced hydraulic
14
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fracture. The results were very encouraging, and the generated
high-pressure/high temperature caused the gel to break. Therefore, it was concluded that this technique effectively contributes
to fracture cleanup in addition to creating the required SRV.
The experiments were very successful in proving the new concept for generating SRV in a tight gas well, and the developed
stimulation technique is fairly easy to implement in the field.
INTRODUCTION
There is tremendous potential for tight gas plays to provide
long-term energy throughout the world because of the vast
resource base that these formations represent. Horizontal
drilling and multistage hydraulic fracturing technologies have
allowed significant gas to be produced from shale gas and tight
sand formations. Yet the primary recovery factors have been less
than 20%, which implies the compelling need for advanced
technologies. The goal of this research effort is to provide a
cost-effective stimulation technique that potentially replaces
costly multistage hydraulic fracturing in shale gas and tight
sand formations.
Water scarcity in the Kingdom requires a new look at fracturing treatments. Energized and waterless fracturing is an
evolving and promising technology that eliminates the polymer
residue within the created fracture and the water phase trapping
within the rock matrix — both of these damaging mechanisms
are associated with conventional water-based fracturing stimulation of tight gas wells. Additionally, the conventional fracturing
must be carefully applied to stimulate tight gas plays because it
is not the single, conductive, and long fracture that one is after;
rather what one wants is the stimulated volume connected to
the well, needed to make it a commercial producer. The current
costly multistage fracturing is helping, but there is a desperate
need for cost-effective stimulation techniques. New alternatives
to hydraulic fracturing are being researched, including tailored
gas fracturing, with the ultimate objective of replacing the
current costly fracturing with a more cost-effective and environmentally friendly treatment that could significantly reduce
stimulation costs.
Several articles have been presented on introducing a pressure pulse loading into a given well to induce near wellbore
fracture1-3. The technique is based on loading a well with a
high-pressure pulse over a short period of time so that the
pressure exceeds all in situ stresses, causing multiple fractures to
propagate in all directions. The fast expanding pulse generates
stress waves, which travel through the rock medium, creating
fractures in the reservoir. A new technique discussed in this article is based on generating a pressure pulse but via an in situ
exothermic chemical reaction.
The pressurization time is the main parameter that determines the fracture pattern. The number of fractures initiated
increases with an increase in loading rate, for loading rates
above the onset pressure. There are three main categories of
fracturing techniques. First is hydraulic fracturing, with the
longest pressure rise time (P ≤ 1 MPa/s), which creates a single
radial fracture. A second technique is using explosives downhole,
which has the shortest rise time (P ≥ 107 Mpa/s) and generates
compacted zones with multiple radial fractures. The third technique is using propellant to generate multiple radial fractures,
which has an intermediate pressure rise time (p ≈ 102 MPa/s
~106 MPa/s). In general, the number of fractures initiated increases with an increase in pressurizing rate for the intermediate pressurizing rate techniques1-3.
Controlling the pressurizing rate is a key factor for controlling the fracture pattern. The new invention describes a new
rock fracturing technique, which has significant advantages
over the three methods just described. With this novel invention,
pressurizing time can be controlled, so a fracturing pattern can
also be optimized1.
The damaging effect of the fracturing technique is another key
factor considered during the fracturing selection process. Detonating an explosive in a wellbore generally creates a damaged
zone surrounding the wellbore wall that impairs permeability
and communication with the reservoir. The pressurization rate
is very high, which causes compressive stresses in the wellbore
area that are much higher than the in situ stress state. This
stress environment can cause compaction or pulverization of a
finite zone around the wellbore to such a degree that permeability is decreased significantly.
CONCEPT
Unconventional gas requires an extensive fracturing network to
create commercially producing wells. One commonly employed
technique is multistage hydraulic fracturing in horizontal wells,
which is very costly and may not provide the required stimulated reservoir volume (SRV). Therefore, a need exists for an
economical method to enhance production within tight gas formations. A new technique has been developed to increase SRV
around the wellbore and fracture area, and therefore improve
unconventional gas production. The method entails triggering
an exothermic chemical reaction in situ to generate heat, gas
and localized pressure sufficient to create fractures around the
wellbore.
In a controlled experiment, chemical reactants were separately injected into core samples with a mini-hole, and upon
their mixing inside the core, an exothermic chemical reaction
occurred and the resultant heat and gas pressure caused
macrofractures. Nuclear magnetic resonance (NMR) porosity
imaging showed a significant increase in macropores throughout
the core. Additionally, large-scale experiments using cement
blocks with a simulated wellbore cavity were performed. Once
the wellbore was filled with the chemicals and a triggering catalyst was introduced, an in situ chemical reaction took place,
which generated heat and gas with sufficient pressure to cause
shear fractures in the surrounding rock. These experiments,
which showed extensive fractured and shattered pieces, also
provided preliminary design requirements for a field test. The
chemical reactants were then incorporated into a fracturing gel
that simulated additional fractures created from the main induced hydraulic fracture. The results were very encouraging,
and the generated high-pressure/high temperature (HPHT)
caused the gel to break. Therefore, it was concluded that this
technique effectively contributes to fracture cleanup in addition to creating the required SRV. The experiments were very
successful in proving the new concept of generating SRV in
tight gas wells, and the developed stimulation technique is
fairly easy to implement in the field.
AUTOCLAVE REACTOR TESTING
Two autoclave reactors, Fig. 1, were used to study the reaction
kinetics of the selected chemicals. One system was rated up to
10,000 psi and 500 °C with a total volume of 3 liters, and the
other was rated up to 20,000 psi. Experiments were carried
out in a dedicated specialized HPHT laboratory equipped with
the required safety features. The experimental parameters were
controlled and PC monitored remotely. Real-time pressure and
temperature data were recorded every 2 seconds to observe the
resulting pressure-temperature behavior during the chemical
reaction. This testing phase was performed to simulate the
pressure and temperature anticipated to occur in a given wellbore as a result of injecting the chemicals and triggering the
reaction. There was one critical assumption; that the well is
drilled in a zero permeability formation to match that of the
autoclave reactor. Although this is not a practical assumption,
Fig. 1. Autoclave systems rated up to 10,000 psi and 20,000 psi.
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it is an approximation of the extremely low permeability when
a well is drilled in a shale formation. There were two independent variables considered in these tests; the molarity of the
chemicals, and the initial pressure and ratio of the chemical’s
volume to the autoclave reactor vessel’s volume.
ENVIRONMENTAL SCANNING ELECTRON
MICROSCOPY (ESEM)
The rock samples were examined in the environmental scanning
electron microscope (ESEM) with an integrated energy dispersive X-ray system. The ESEM equipment was operated at 15
kV, 0.4 Torr water vapor pressure and around 8 mm working
distance. Useful and insightful textural information on the two
formations was obtained by acquiring surface images from different parts of the examined samples. The samples were mounted
on ESEM holders using double-sided carbon tape, and then the
samples were inserted into the ESEM chamber for analysis.
fracturing gel. The fracturing gel was water-based WG-17,
with a loading of 40 lb/Mgal. The viscosity of this fluid was
about 1,600 centipoise (cP) at a share rate of 81 s-1 at room
temperature. The concentrations of the exothermic chemicals
varied from 3 molar to 5 molar and were used immediately after preparation. The injection rate was about 30 cc/min to 100
cc/min.
Samples were tested with and without confinement. For the
confined stress testing, samples were loaded in a biaxial cell
with equal horizontal stresses of 2,000 psi for one test and
4,000 psi for another test. If we consider a well depth of 2,570
ft, these stresses represent gradients of 0.78 psi/ft and 1.56
MR-CT MICROSCOPE
A magnetic resonance and computed tomography (MR-CT)
microscope is a new suite of core analysis tools that utilizes
NMR combined with X-ray CT to improve the description of
pore property changes as a result of coreflooding with different
types of fluids4. The MR-CT microscope allows the observation of microscopic events within reservoir porous media and
provides fluid-rock interaction with proper mineralogy quantification information. Both a medical CT scan and a micro CT
scan were also used to evaluate the chemical treatment on the
carbonate cores.
ROCK BLOCK TESTING
A series of laboratory experiments were conducted to provide
insight on applying the concept of chemically induced pulse
fracturing in the field. Rock samples used in these experiments
were rectangular blocks with dimensions of 8” x 8” x 8” and
10” x 10” x 10”. Each rock sample was made to have a 1½” x
3” cavity to simulate a wellbore. The tested rocks were Indiana
limestone, Berea sandstone, shale and cement. The man-made
rock samples were cast by mixing water and cement with a
weight ratio of 31/100, respectively.
The physical and mechanical properties of the rock samples
were: porosity = 29%, bulk density = 1.82 gm/cc, Young’s
modulus = 1.92 x 106 psi, Poisson’s ratio = 0.26, uniaxial
compressive strength = 3,299 psi, cohesive strength = 988 psi
and internal friction angle = 28°. The breakdown pressure for
this test was 5,400 psi.
A vertical open hole was cast or drilled in the center of the
block. For the unconfined test, the simulated wellbore was 3”
long and 1½” in diameter, Fig. 2. For the confined test, the
vertical open hole was cast all the way through the center of
the block, Fig. 3. The exothermic chemicals were used with a
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Fig. 2. Block design for unconfined tests.
Fig. 3. Block design for confined tests.
UNCONFINED CONDITION TESTING
1.82 gm/cc, Young’s modulus = 1.92 x 106 psi, Poisson’s ratio
= 0.26, uniaxial compressive strength = 3,299 psi, tensile
strength = 271 psi, cohesive strength = 1,067 psi and internal
friction angle = 23°.
Tests 1 and 2
Test 4
The samples for this type of test, which simulated an open hole
vertical well, were man-made cement blocks. The rock samples
were preheated to 200 °F. Then reactive chemicals were injected
in the rock at atmospheric pressure and at a rate of 15 cc/min.
As chemical injection was completed and the reaction took
place, multiple fractures were created, as shown in Figs. 4 and
5. The created fractures were longitudinal and perpendicular
with respect to the vertical wellbore. The fracture geometry indicates that fractures propagated from the wellbore to the end
of the sample. This indicates that the pressure generated was
greater than the compressive strengths of the samples. The
breakdown pressure for these tests was 5,400 psi.
A shale block sample from Mancos was used for this test with
a drilled hole 2” long and 1½” in diameter, to simulate a vertical open hole well. In this test, the reactive chemicals were injected first, then the block was placed in a 200 °F oven. After 3
hours, a chemical reaction took place and multiple fractures
were created, Fig. 7. The time interval for the reaction to be
activated simulated the downhole temperature recovery of the
wellbore. The breakdown pressure for this test was 6,600 psi.
The physical and mechanical properties of the shale rock samples were: porosity = 3.8%, bulk density = 2.50 gm/cc, Young’s
modulus = 2.66 x 106 psi, Poisson’s ratio = 0.20, uniaxial compressive strength = 4,965 psi, cohesive strength = 1,268 psi and
internal friction angle = 36°.
psi/ft, respectively. The reactive chemicals were injected in the
block and heat was applied using the biaxial plates.
Test 3
The Indiana limestone block sample was used for this test with
a drilled hole 3” long and 1½” in diameter, to simulate a vertical open hole well. The block was preheated to 200 °F, then
reactive chemicals were injected in the rock at atmospheric
pressure and at a rate of 15 cc/min. As chemical injection was
completed and the reaction took place, multiple fractures were
created within two minutes, Fig. 6. The created fractures were
two longitudinal and one perpendicular with respect to the vertical wellbore. The breakdown pressure for this test was 4,700
psi. The physical and mechanical properties of the Indiana
limestone rock samples were: porosity = 28%, bulk density =
CONFINED CONDITION TESTING
Samples for this test simulated a vertical open hole well with a
hole drilled in the center of an 8” x 8” x 8” cube, Fig. 8. The
hole was 1½” in diameter, extending throughout the whole
length of the sample, as previously shown in Fig. 3. The test
sample was then placed in a biaxial loading frame where two
horizontal stresses of a given stress were applied while the
vertical stress was controlled by mechanical tightening of the
Fig. 6. Pre- and post-treatment views of Indiana limestone block sample, using
chemically pulsed fracturing.
Fig. 4. Pre- and post-treatment views of white cement block sample, using
Fig. 5. Pre- and post-treatment views of portrait cement block sample, using
Fig. 7. Pre- and post-treatment views of shale block sample, using chemically
pulsed fracturing.
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Fig. 8. 8” x 8” x 8” cement block.
base and top platens, Fig. 9. Then reactive chemicals were injected in the rock at atmospheric pressure and room temperature
at a rate of 15 cc/min. The sample was then heated for 2 to 3
hours until the reaction took place and fractures were created.
Two tests were performed as follows.
Fig. 9. Biaxial system for confined condition tests.
Test 5 and 6
For Test 5, the applied horizontal stress was 2,000 psi at both
directions, Fig. 10. The reaction was triggered at 167 °F. Upon
triggering the reaction, three longitudinal and one perpendicular fractures were created with respect to the vertical hole, Fig.
11. The applied horizontal stress in Test 6 was 4,000 psi at
both directions, Fig. 12. Almost the same behavior was observed for this test. Four longitudinal fractures were created
with respect to the vertical hole, Fig. 13. The fracture geometry
shows that the created fracture was longitudinal with respect
to the vertical wellbore. The fracture geometry indicates that
two sets of fractures propagated from the wellbore to the end
of the sample. This indicates that the pressure generated was
greater than 8,000 psi. Each created planar fracture propagated
in the direction of one σH and perpendicular to the direction
of the other σH, as the applied stress is equal in both horizontal
directions.
REACTOR TESTING
An autoclave reactor, rated up to 10,000 psi, was used to test
the chemical reaction. Figure 14 shows a typical reaction
behavior with pressure and temperature pulses. In this test,
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Fig. 10. Pulsed fracturing under 2,000 psi biaxial stress.
reactive chemicals were placed in the autoclave at room conditions. Then the temperature was increased until reaction was
triggered at 120 °F. The pressure rise time was less than 2 seconds, which is the machine’s low limit. So, depending on the
pressurizing rate, multiple fractures were expected to be generated in the rock samples.
The initial pressure does not have a negative impact on the
Fig. 11. Fractured cement block under 2,000 psi biaxial stress.
Fig. 14. Chemical reaction at zero psi initial pressure and 2X solution volume.
Fig. 12. Pulsed fracturing under 4,000 psi confined stress.
Fig. 15. Chemical reaction at different initial pressure.
Fig. 13. Fractured cement block under 4,000 psi biaxial stress.
generated pressure pulse. As can be seen in Fig. 15, the final
pressure is a function of the initial pressure. In other words,
final pressure is the summation of initial reactor pressure and
reaction generated pressure; however, the temperature was
almost constant with the changes in initial pressure at fixed
chemical concentration and volume.
In another test, reactive chemicals were prepared with crosslinked fracturing gel (40 lb/1,000 gal), Fig. 16. The solution’s
pH was adjusted to 9.7. Then the gel was injected into the
reactor, which was preset at 200 °F. The reaction was not triggered for 1 hour, not until the gel breaker was injected. When the
gel breaker was injected, which reduces the solution pH, the
pressure pulse was generated. This characteristic can give more
control over the reaction behavior for field applications.
Fig. 16. Activation of cross-linked gel containing reactive chemicals using a breaker.
EFFECT OF CONCENTRATION AND VOLUME
The chemicals were tested using an autoclave at different concentrations and solution volumes. The results showed that
pressure is a function of chemical concentration and volume.
The greater the solution volume used, the greater the generated
pressure, Fig. 17. At 50 vol%, the pressure increased from 988
psi to 6,100 psi and then to 16,600 psi, as the concentration
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was increased from 1x to 3x and then to 4x, respectively.
These are actual data measured using the autoclave system.
Tests also showed that the greater the concentration, the
higher the generated pressure was. As the solution volume was
increased from 50 vol% to 100 vol%, the generated pressure
that was measured increased from 988 psi to 20,000 psi. It is
anticipated that the pressure can exceed 45,000 psi using
chemicals at high concentrations and large volumes.
TRIGGERING TEMPERATURE
Figure 18 shows that the reaction triggering temperature was
around 200 °F at zero initial reactor pressure and a 6.5 pH
solution. Once this temperature was reached, the reaction
progressed vigorously and reached maximum pressure and
temperature in milliseconds. The minimum limit of the autoclave system was 2 seconds, so it was not possible to record
the reaction pulse duration. During experiments with an initial
reactor pressure of 350 psi and higher, the triggering temperature was stabilized round 122 °F. When the solution pH was
increased from 6 to 9, the triggering temperature increased
from 200 °F to 230 °F, at zero initial pressure. At an initial
pressure of 500 psi, the triggering temperature was increased
from 122 °F to 184 °F, as the pH increased from 6.5 to 9.
SYNTHETIC SWEET SPOT
Microscopic analysis of a sample treated with the reactive
chemicals showed that no damaged zone was formed around
the treated area; however, a synthetic sweet spot was created,
Figs. 19 and 20. A tight core sample with an air permeability
of 0.005 nano-darcy was chemically treated using the coreflood system. The chemical was injected through a drilled hole
within the core sample, two-thirds of the total core sample
length, 3.2”. The core diameter was 1½” with porosity of
1.35%. Pre- and post-treatment CT scan analysis shows significant density reduction, also seen in Figs. 19 and 20. Voids are
scattered around the treated area throughout the core sample.
The change in slice colors from red and green to green and
blue indicates a reduction around the treated area, which reflects an increase in porosity. ESEM analysis shows that microfractures were created along the core sample. The MR-CT
microscope image also shows visible voids and high porosity
around the treated hole, Fig. 20, which was confirmed by
ESEM analysis. Several backscattered electron topographical
Fig. 17. Effect of chemical concentration and volume on pressure pulse.
Fig. 19. Pre-treatment tight core sample (MR-CT, ESEM and CT scan).
Fig. 18. Reaction triggering temperature behavior.
Fig. 20. Post-treatment tight core sample with synthetic sweet spot, (MR-CT,
ESEM and CT scan).
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images were taken at different magnifications from different
parts of the samples, but mainly from the center of the rock
samples. The acquired images show submicron pores and microcracks. The sizes of the pores were measured and found to be
in the range of less than 1 micron to 50 microns. The concentration of the cracks and pores was mainly in the center of the
rock, where the epicenter of the treatment took place. The
exothermic reaction treatment thereby led to the initiation of
micro-cracks and pores in the rock samples4, 5.
MR-CT MICROSCOPE
The pre- and post-treatment MR-CT microscope results show
a significant increase in macropores throughout the core and
suggest communication among an otherwise isolated system of
micro-, miso- and macropores of the core, with an overall permeability increase. Figure 20 also shows the isolated porosity
system of the pre-treatment core sample, where the micro-,
miso- and macropores are clearly not communicating with
each other; however, post-treatment results show strong communication among all pore sizes6.
CT-SCAN OF RM9 AND RM13
Fig. 21. Reactive gel with proppant.
The pre- and post-treatment medical CT scan images of the
treated core samples show a significant porosity increase and
numerous created fractures due to the chemical reaction, previously seen in Figs. 19 and 20. The red color represents high
density and low porosity sites, while the blue color represents a
low density and high porosity system. Pre- and post-treatment
images of a tight core sample show the creation of fractures
perpendicular to the flow of injection. A clear reduction of
density and porosity is noted. Fractures and voids are clearly
shown in black in both samples.
VISCOSITY AND COMPATIBILITY WITH FRACTURING
FLUID
The reactive chemicals were prepared and showed compatibility
with the cross-linked fracturing fluid, Fig. 21. The gel, containing reactive chemicals, was also prepared with proppant and
again showed compatibility, Fig. 22. The gel was activated in
the autoclave system by heating to the triggering temperature.
The heat generated by the reaction broke the gel viscosity, even
without injecting the gel breaker, Fig. 23. Therefore, this type
of treatment can help clean up the well after a fracturing job.
Using a Chandler viscometer, the viscosity of the cross-linked
gel, containing reactive chemicals, was measured pre- and
post-reaction. The gel viscosity was reduced from 1,600 cP to
10 cP, Fig. 24. This indicates the reactive chemicals can fully
break the gel viscosity, which can help in fracture cleanup.
Fig. 22. Pre-reaction gel.
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Fig. 24. Reaction effect on breaking cross-linked gel viscosity.
Fig. 23. Post-reaction gel.
Fig. 25. Cooling effect of preflush on downhole temperature.
REACTION ACTIVATION METHOD FOR FIELD
APPLICATION
Injecting a preflush reduced the downhole temperature from
250 °F to 100 °F, Fig. 25. The cooling effect and heat recovery
of the treated well can be used to self-activate the reactive
chemicals. By selecting the optimum pH, the reactive chemicals
can take from 1 to 3 hours to be activated, depending on the
designed procedures and required need. From Fig. 25, results
show it took around 4 hours for the downhole temperature to
reach 184 °F, which is the triggering temperature of the reactive
chemicals using a 9 pH solution. This gives sufficient time to
place and self-activate the gel downhole.
CONCLUSIONS
1. A new shale or tight gas stimulation technique has been
developed using chemical reaction and has been proven
through laboratory experiments. This new approach is
based on pulsed fracturing.
2. Multiple fractures were created using the new technique in
shale, Indiana limestone, Berea sandstone and cement
block samples. Fracturing was also tested, using cement
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block samples, under a stress level of 4,000 psi.
3. This technique can be used to increase SRV in shale or
tight gas wells. The technology can also be applied to
stimulate limestone and sandstone formations.
4. The simplicity of this technique makes it very attractive to
implement. The applicability of this technique has been
demonstrated in the laboratory and a field trial is being
planned. There is no special tool required to apply the
technology in the field, compared to propellant techniques.
5. The reactive chemicals are compatible with the fracturing
fluid and can be activated by either reservoir thermal effect
or pH reduction.
6. A synthetic sweet spot is created around the treated area of
tight rock samples using the new chemical treatment
method. This confirms that no damaged zone will be
formed.
7. The new technology can enable fracture cleanup.
ACKNOWLEDGMENTS
This article was presented at the Unconventional Resources
Technology Conference, Denver, Colorado, August 25-27, 2014.
REFERENCES
1. Swift, R.P. and Kusubov, A.S.: “Multiple Fracturing of
Boreholes by Using Tailored-Pulse Loading,” Society of
Petroleum Engineers, Vol. 22, No. 6, 1982, pp. 923-932.
2. Cuderman, J.F.: “Tailored-Pulse Fracturing in Cased and
Perforated Boreholes,” SPE paper 15253, presented at the
SPE Unconventional Gas Technology Symposium,
Louisville, Kentucky, May 18-21, 1986.
3. Yang, D.W. and Risnes, R.: “Experimental Study on
Fracture Initiation by Pressure Pulses,” SPE paper 63035,
presented at the SPE Annual Technical Conference and
Exhibition, Dallas, Texas, October 1-4, 2000.
4. Al-Nakhli, A.R., Abass, H.H., Kwak, H.T., Al-Badairy, H.,
Al-Ajwad, H.A., Al-Harith, A., et al.: “Overcoming
Unconventional Gas Challenges by Creating Synthetic
Sweet Spot and Increasing Drainage Area,” SPE paper
164165, presented at the SPE Middle East Oil and Gas
Show and Conference, Manama, Bahrain, March 10-13,
2013.
5. Al-Ajwad, H.A., Abass, H.H., Al-Nakhli, A.R., Al-Harith,
A.M. and Kwak, H.T.: “Unconventional Gas Stimulation
by Creating Synthetic Sweet Spot,” SPE paper 163996,
presented at the SPE Unconventional Gas Conference and
Exhibition, Muscat, Oman, January 28-30, 2013.
6. Kwak, H.T., Funk, J.J., Yousef, A.A. and Balcom, B.J.:
“New Insights into Microscopic Fluid/Rock Interaction:
MR-CT Microscopy Approach,” SPE paper 159194,
presented at the SPE Annual Technical Conference and
Exhibition, San Antonio, Texas, October 8-10, 2012.
BIOGRAPHIES
Ayman R. Al-Nakhli is a Petroleum
Scientist with the Production
Technology team of Saudi Aramco’s
Exploration and Petroleum
Engineering Center – Advanced
Research Center (EXPEC ARC),
where he is involved in the study of
His main research interest is
unconventional reservoirs.
reserv
developing new technologies in the field of fracturing,
stimulation, heavy oil recovery, unconventional gas and
smart fluids. Ayman has generated several patents and
published several papers related to production technology.
He has also published a book about self-development.
He received his B.S. degree in Industrial Chemistry from
King Fahd University of Petroleum and Minerals (KFUPM),
Dhahran, Saudi Arabia, and an MBA from Open
University Malaysia, Bahrain.
Dr. Hazim H. Abass was a Senior
Consultant at Saudi Aramco’s
Research Center (EXPEC ARC). He
has advanced the geomechanics
discipline by developing practical
applications
to solve
li i
l petroleum related problems. Hazim
has pioneered advanced techniques related to oriented
perforation, fracturing horizontal wells, acid fracture
closure, sanding tendency, gas hydrate and water coning.
Before joining Saudi Aramco in 2001, he worked for the
Northern Petroleum Organization in Iraq, the Halliburton
Research Center in Oklahoma and the PDVSA Research
Center in Venezuela.
Hazim is the recipient of the 2008 SPE Middle East
Regional Award, Production Operations; the 2009 SPE
International Award, Distinguished Member; the 2012 SPE
International Award, Completion Optimizations and
Technology; and the 2012 SPE Middle East Regional
Award, Completion Optimizations and Technology. He was
one of the SPE Distinguished Lecturers for the 2011/2012
season, educating professionals around the globe on “the
use and misuse of applied rock mechanics in petroleum
engineering.”
Hazim holds 10 U.S. patents, has authored more than
40 technical papers and contributed to three industrial
books. He is a member of the Society of Petroleum
Engineers (SPE) and the Technical Editor of its journal
Production & Facilities, and he is a member of the
International Society for Rock Mechanics (ISRM).
In 1977, Hazim received his B.S. degree in Petroleum
Engineering from the University of Baghdad, Baghdad,
Iraq. He received his M.S. and Ph.D. degrees in 1987 in
Petroleum Engineering from the Colorado School of Mines,
Golden, CO.
He retired from Saudi Aramco in September 2014.
Mirajuddin R. Khan joined Saudi
Aramco in 1991. He is a Geologist
working in Saudi Aramco’s
Research Center (EXPEC ARC). His
interests are rock mechanics’
applications in petroleum
engineering. Mirajuddin is a
petro
member of the Society of Petroleum Engineers (SPE) and
has published several technical papers.
Before joining Saudi Aramco, Mirajuddin worked as a
Teaching Assistant for 1 year and then received a
scholarship to work as a Research Scholar for 2 years at
the University of Karachi.
His awards include the 2004 Recognition Award of the
Engineering & Operations Services of Saudi Aramco.
Mirajuddin received his B.S. degree in 1984 and his
M.S. degree in 1985, both in Petroleum Geology from the
University of Karachi, Karachi, Pakistan.
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23
Victor V. Hilab is a Petroleum
Engineer with the Production
Technology team of Saudi Aramco’s
Research Center (EXPEC ARC). He
has 36 years of experience working in
chemistry
laboratories,
h i
l b
i of which 26 years has been with
Saudi Aramco. Victor’s areas of interest are research in
formation damage analysis and remediation, scale
problems, wastewater disposal, and injection water quality
and fracturing. He is currently working in laser and heavy
oil research.
Victor is a member of the Society of Petroleum
Engineers (SPE) and the American Chemical Society (ACS).
He has authored and coauthored many papers throughout
his career. Victor also has one granted U.S. patent.
He received his B.S. degree in Chemical Engineering
from FEATI University, Manila, Philippines.
Ahmed N. Rizq is a Lab Technician
with the Production Technology team
of Saudi Aramco’s Exploration and
Petroleum Engineering Center –
Advanced Research Center (EXPEC
ARC). He has several years of
experience, working with the
Geochemistry Division
Divisio for 3 years, the R&D Division for 1
year and the Geology Technology team for 2 years.
Ahmed’s interests include unconventional resources and
reducing the cost of production.
from Jubail Industrial University, Jubail, Saudi Arabia.
Ahmed S. Al-Otaibi joined the
Industrial Training Center in 2008, for
a 2 year program. He then went on to
study at Jubail Industrial College for
10 months, graduating in July 2011.
Ahmed then joined Saudi Aramco as a
Lab Technician with the Production
Technology
T chnology Team
Te
T am of Saudi Aramco’s Exploration and
Te
Petroleum Engineering Center –Advanced Research Center
(EXPEC ARC).
24
WINTER 2014
Integrating Intelligent Field Data
into Simulation Model History
Matching Process
Authors: Bevan B. Yuen, Dr. Olugbenga A. Olukoko and Dr. Joseph Ansah
ABSTRACT
The advent of digital oil field technology initiated a new era of
real-time data acquisition, which facilitated continuous field
monitoring and swift intervention. Although yesterday’s or the
last hour’s real-time data is not “real time,” it can be classified
as intelligent field data. Raw intelligent field data is usually
recorded and stored in second or minute intervals, and the
volume of the data has been continuously increasing. Yet the
added value of the intelligent field data so far has outweighed
the challenges in the storage, validation and summarization of
such huge amounts of data. While reservoir engineers often
struggle with historical well data that is limited in nature and
is measured at different time intervals, the continuous and synchronized data stream emerging from the intelligent field provides unique opportunities to improve the history matching
process of reservoir simulation models.
In this article, we present the data utilization and the workflows adopted to integrate such data into reservoir simulation
modeling. The workflow was devised to manage data quality,
consistency, conversion and reconciliation with allocation
data. Challenges lie in the selection of the intelligent field data
to match, and in simulator reported pressure and time stepping.
Continuous and synchronized data streaming in real time means
that data is available to the engineer almost instantly or within
a short time frame from acquisition. The wealth of data enables
the simulation engineer to appropriately diagnose and account
for critical reservoir phenomena, such as well interference and
subsurface well responses to surface well actions. Successful
integration of intelligent field data into reservoir simulation
significantly enhances the quality and predictability of our
models. This builds on the success of our high resolution geological models that attempt to capture all spatial heterogeneities.
In much the same way, high resolution temporal data attempts
to capture all dynamic actions and reactions within the reservoir
to further improve the reservoir simulation models.
INTRODUCTION
systems has been developed to measure, capture, store,
process, manage and visualize massive amounts of data for
real-time decision making2, 3. The boundary of the technology is
always being pushed to get systems to provide more subsurface
multi-station, multivariable, multiphase real-time measurements
along a wellbore. The availability of such large amounts of
complex data has been a challenge for the industry to handle,
and companies are developing a growing number of applications
to transform this data into useful information. Al-Mulhim et al.
(2010)4 and AbdulKarim et al. (2010)1 both described the
application of intelligent field data in the area of real-time control in oil and gas field operations. Yuen et al. (2011)5 described
intelligent field data as one of the four major evolving technological developments influencing advanced reservoir simulation
practices in the oil and gas industry; the other three are high
resolution geological modeling, Thomeer pore description and
high performance computing clusters.
High resolution reservoir modeling attempts to capture significant heterogeneities on a small physical scale. The high
resolution temporal data generated by intelligent field operations
capture pressure responses on a small time scale, yet in reservoir
simulation practice, reservoir engineers are often encouraged
to use algorithms that enable simulators to take large time
steps during the computation to reduce computing time and
resources. This is even more so the case with models that are
spatially high resolution — with hundreds of millions of cells.
Confronted with high frequency real-time data, engineers face
the dilemma of either running the simulator in smaller time
steps, in line with the high frequency data, or adhering to the
large time step practice. Some prefer to reduce the high frequency well rate data to a lower frequency to decrease the
computing time. Others choose to ignore the real-time data
and only use it qualitatively to guide the simulation study. In
Saudi Aramco, our preferred approach is to run the simulation
models at daily average time steps, which is made possible by
our in-house GigaPOWERS simulator — Saudi Aramco’s gigacell parallel reservoir simulator. This lets us take full advantage
of intelligent field data and high resolution models without
compromising on quality.
Digital oil field technology is now mainstream and its deployment by oil and gas companies has been going on for some
years1. A robust platform comprising hardware and software
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INTELLIGENT FIELD DATA TYPES FOR SIMULATION
MODEL HISTORY MATCHING
By design, intelligent fields are equipped to gather and store
massive amounts of different types of data in real time from
sensors that monitor reservoir response and the operation history of the production equipment installed in individual wells
and surface facilities. The rationale behind this effort is that
different entities within an organization or company use different sets of the same data. By applying a diverse set of software
and tools, these different groups within the organization can
analyze the real-time data to ensure efficient oil and gas production, as well as optimize fluid injection systems that support this production.
In reservoir simulation, only a subset of the intelligent field
data is essential for proper history matching of the simulation
models that will be used to monitor reservoir performance and
forecast future production and injection requirements:
• Oil, gas and water production rates.
• Water and/or gas injection rates.
• Reservoir pressure.
In a typical intelligent field, production wells are equipped
with multiphase flow meters (MPFMs) that provide oil, gas
and water production rates in real time. These production
wells are additionally equipped with wellhead pressure (WHP)
and temperature sensors that measure and store real-time pressures and temperatures. In some fields, pressure and temperature
gauges are installed downhole to enable pressure and temperature measurements closer to the reservoir, ensuring accurate
reservoir pressure data gathering, especially during production.
The wellhead is also equipped with a choke system that remotely
regulates fluid production from individual wells. In this system,
choke position sensors provide real-time choke position, which
is one of the key parameters for verifying the status of a well
— open or closed.
Fig. 1. Tabulated intelligent field data types relevant to reservoir simulation.
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All injection wells are equipped with wellhead water rate
meters that provide fluid injection rate data in real time. In addition, injectors are equipped with pressure and temperature
gauges that provide real-time injection pressures and temperatures
at the wellhead. These wells are further equipped with surface
chokes to enable the injection of precise volumes of fluid.
Static reservoir pressures are provided by dedicated observation wells located in key sectors of the field. These observation
wells are equipped with permanent downhole measurement
systems (PDHMS) that continually measure and transmit realtime downhole static pressures and temperatures via the field
supervisory control and data acquisition system to intelligent
field servers, where they are stored. These static pressures, in
combination with flowing and static reservoir pressures determined from the production and injection wells, are keys for
history matching reservoir simulation models.
The raw intelligent field data from different sources are filtered through special software tools to remove any outliers
and then summarized on an hourly or daily basis, together
with calculated parameters, such as water cut and gas-oil ratio
(GOR), into a usable format, Fig. 1.
The data is also plotted to observe trends and identify logical
and consistent data responses, especially when the wells are
flowing or shut-in. Sample plots of the intelligent field data for
oil producers and water injectors are shown in Figs. 2 and 3,
respectively. In these plots, oil production, water production
and water injection rates, together with flowing bottom-hole
pressure (FBHP) and WHP, are plotted in real time.
KEY CONSIDERATIONS FOR INTELLIGENT FIELD DATA
INTEGRATION INTO RESERVOIR MODELING
The availability of high frequency intelligent field data is beneficial for reservoir simulation modeling. The continuous pressure
and rate stream, however, needs to be carefully incorporated
Fig. 2. Intelligent field data — oil and water production rate and FBHP profiles.
Fig. 3. Intelligent field data — water injection rate and WHP profiles.
into the history matching process. The following are some key
steps to be considered for the utilization of intelligent field
data in history matching when compared to conventional data.
Data Quality
Prior to utilizing the intelligent field data for history matching,
it is important to ensure data quality and consistency between
the datasets, such as checking that buildups/falloffs correspond
to zero production/injection periods. Data quality degradation
is usually due to instruments malfunctioning, breaking down
or being down for operational reasons. This can happen to
gauges, meters, data relay units and servers. Data missing over
a short period of a few days may not have a big impact on
simulation model history matching. For longer durations and
wider fluctuation, the missing data must be backfilled and filtered by well models, expert systems or smart algorithms. Data
consistency problems typically manifest as illogical responses
between pressure and rate data, such as getting non-zero
production rate measurements while the pressure gauge data
indicates a well is shut-in, or vice versa. Figure 4 shows an example of inconsistent data; the FBHP of an oil producer is rising toward the end with zero production rates, but the choke
position shows that the well is still open. This was resolved
through an integration of data and well rules. Tools that can
quickly ensure quality assurance/quality control of the large
amount of data are indispensable.
Data Summarization and Conversion
As previously seen in Figs. 2 and 3, the measurement frequency
of intelligent field rates and pressures (hours: minutes: seconds)
is often impractical for reservoir simulation purposes. On the
other hand, conventional monthly production rates and infrequent wireline static pressure measurements are sometimes too
far from reality. A compromise of daily average rates and pressures may be sufficient, depending on simulation hardware
availability. Intelligent field data cannot be used directly and
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27
Fig. 4. Producer missing data and inconsistent data.
must go through a conversion process prior to being used in
reservoir model history matching. In reservoir simulation, well
FBHP at top perforation and static well pressure at datum are
calculated from dynamic flow and well equations. During history
matching, the calculated pressures need to be compared to the
measured pressures to determine the quality of the match. To
achieve this, the producer’s FBHP is corrected to top perforation,
and the injector’s WHP is converted to FBHP. These conversions
usually introduce some uncertainties, but to an acceptable
degree. Further conversion of a well’s FBHP to static pressure
may be carried out by introducing an assumed well productivity
index (PI)/injectivity index (II), which involves additional uncertainties and is not recommended in instances where accurate
static bottom-hole pressures (SBHP) are needed.
case, the MPFM rate is close to the allocated rate, leading to
high confidence in the MPFM data used for history matching.
Data Reconciliation
Since the field pressure data are instantaneous measurements
at the well location, the well pressure output to be considered
for the simulator should be based on the well average gridblock pressures rather than average drainage area pressures.
This is because the latter attempts to mimic a field static pressure survey of a few hours or a couple of days for a shut-in
period of a well by estimating the average drainage area pressure away from the well when the producing well is not actually
shut-in, then use that estimation of static pressure in the model.
For producer wells, however, a drainage area averaging method
Intelligent field data provides individual well flow rate measurements. Reconciliation with the allocated monthly data for
total field measurement is usually difficult. In theory, the whole
is the sum of the parts, but in reality, there is usually a difference
due to inexact meter calibration, missing data, out of range
measurements and/or losses in the gathering and injection
trunk lines. One analysis of producer rate data shows that the
correction factor is centered on 1.0, Fig. 5. Therefore, in this
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Focus on Shut-in Periods for Static Pressure Match
During the initial material balance step of the history matching,
where the objective is matching the reservoir pressures while
prescribed fluid volumes are withdrawn, the primary focus
should be on the shut-in periods for producers and injectors, i.e.,
the buildup and falloff pressures, in addition to the observed
well static pressures.
Utilize Model Cell Average Static Pressures Rather than
Drainage Area Pressures
will usually estimate a higher well static pressure than the cell
average technique, especially for low permeability reservoirs,
Fig. 6. Today, such averaging is no longer required as the
model will be run using the same (daily averaged) time steps as
the intelligent field data, which includes actual shut-in time.
Calibrate Well Index for FBHP Matching
producing or injecting, i.e., using the FBHP, requires that the
well’s PI/II be defined and/or calibrated in the model. These
should be specified in the model input if measurements are
available and thereafter tuned to match the FBHP data. It
should be noted that the well’s PI/II may vary during a well’s
producing life due to the changing operating conditions, e.g.,
acid stimulation, fines migration, thermal fracturing (for water
injectors), etc.
Utilization of the intelligent field pressure data while a well is
Fig. 5. Well production rate reconciliation analyses.
Fig. 6. Static cell pressure average and drainage area pressure average comparison.
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WORKFLOW FOR INTEGRATING INTELLIGENT FIELD
DATA IN SIMULATION MODEL HISTORY MATCHING
The workflow described here has been used in history matching several reservoir simulation models and is also being continuously used for updating the models.
1. Summarize the intelligent field data into daily interval time
steps. This involves filtering, removing outliers and ensuring
the consistency of the raw data. This can be done by an expert system, statistical algorithms, logical rules and mathematical models.
2. Reconcile the intelligent field rates with allocation rates.
3. Convert the oil, gas and water production and injection
daily rates by wells into the reservoir simulator input format.
4. Convert the producer’s FBHP from gauge depth to the top
of the perforation. Similarly, convert the WHP of the injectors to FBHP by using single-phase vertical flow equations.
The observation well’s pressures are also converted from
gauge depth to datum depth. More sophisticated well models can be used for the conversion.
5. Add new wells to the simulation model.
6. Perform the reservoir simulation with at least a weekly out
put of well pressure, water cut and GOR. Pressure responses
may be missed if done at a monthly interval.
7. Match the static pressure of observation wells and also the
static pressures during the shut-in periods of producers and
injectors.
Fig. 7. Producer FBHP, oil production rate and water cut matches.
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8. Fine-tune the well’s PI/II as necessary to match FBHP. With
reasonable permeability around the well after matching well
static pressure, the well’s FBHP usually falls in place. If an
extremely small or large PI or II is required to match a
well’s FBHP, then the reservoir permeability is most likely
incorrect.
EXAMPLE RESULTS OF INTELLIGENT FIELD DATA
INTEGRATION IN MODEL HISTORY MATCH
By using the workflow just described, the high frequency rate
and pressure data were incorporated in a simulation model.
The history matching process was carried out the usual way
using a combination of manual and assisted history match
tools. Traditional history matching uses monthly average allocated rates with infrequent SBHP measurements, resulting in a
wider uncertainty of the reservoir model. The averaged and
nonsynchronized nature of non-intelligent field data means
that the data do not capture the actual rates that correspond to
the pressure responses from the well itself and from any well
interference. A model that is matched to intelligent field data
has reduced uncertainty due to the increased degree of constraints in the data. Most of the wells show a very good match
with the high frequency pressure data and to a lesser degree
with the water cut measured by MPFMs or from the allocation
data. Figure 7 is an example of a history matched producer.
The FBHP match, which is very good, was achieved by
following the approach to match the shut-in pressure, then
fine-tune the FBHP with modifications to the well’s PI. A calibrated well PI tuned to continuous FBHP measurements will
give more credence to subsequent model predictions for this
well as compared to predictions using a traditional model that
is history matched to only conventional data. Water cut allocation issues are evident in the difference between the MPFM
data and the allocated data, as previously shown in Fig. 7. In
this example, we chose to match the intelligent field data water
cut rather than the allocation data due to a decreasing trend in
the latter — in the absence of any well intervention — which
indicates that the allocated data is less reliable. Figure 8 shows
a fairly good match of the SBHP during well shut-in as estimated from the intelligent field FBHP.
The SBHP determined by the PDHMS is the most reliable
data and requires very little processing and conversion. The
SBHP match of an observation well is shown in Fig. 9, with
pressure confirmation from wireline measurements (the period
in the graph that shows a lot of erratic measurement was due
to electric system glitches). Figure 10 shows the FBHP history
Fig. 8. Producer SBHP match.
Fig. 9. Observation well SBHP match.
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Fig. 10. Water injector FBHP match.
match for a water injector. Daily water injection rates were
specified as input to the simulation model and the goal was to
match the FBHP derived from the WHP. Frozen flow meter
data and differences with the allocation rates are evident. As
most of the injectors were cleaned and not stimulated, a good
match of the FBHP was achieved via modifications to model
permeability rather than to the well’s II.
ADVANTAGES OF INTEGRATING INTELLIGENT FIELD
DATA
The main advantage of integrating high frequency real-time intelligent field data for reservoir simulation modeling is the improvement in the model quality and reliability. Connectivity
between wells can be calibrated more reliably using high resolution rate and pressure data. As long as the flow meters are
frequently calibrated, the rate data is more reliable than the
conventional data acquisition, which is often combined with
infrequent well test data. Well examples previously shown
clearly highlight the difference between intelligent field data and
allocation data, which is the majority of data collected and
stored in the past. In addition, high frequency pressure data
should enhance the history match quality, as opposed to the
data from conventional and infrequent wireline pressure surveys.
CONCLUSIONS
Our experiences in history matching several reservoir simulation
models to intelligent field data show that:
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1. Filtering, processing, correction and conversion of the intelligent field data are required before it is usable for history
matching.
2. Intelligent field data show that well rates and pressures vary
considerably with time. Well events are accurately captured,
which is impossible with monthly average rates and infrequent static shut-in pressure measurements.
3. A detailed workflow for history matching intelligent field
data was developed.
4. The most accurate static pressure data is from observation
wells and during producer/injector shut-in. These pressures
should be given the highest priority during history matching.
The FBHP matches can be fine-tuned using an individual
well’s PI/II.
5. A reservoir simulation model history matched to intelligent
field data is more reliable for both short-term and long-term
prediction purposes since it is calibrated to a more extensive
dataset than conventional monthly rates and infrequent
static pressure data.
ACKNOWLEDGMENTS
REFERENCES
1. AbdulKarim, A., Al-Dhubaib, T.A., Elrafie, E. and
Al-Amoudi, M.: “Overview of Saudi Aramco’s Intelligent
Field Program,” SPE paper 129706, presented at the SPE
Intelligent Energy Conference and Exhibition, Utrecht, The
Netherlands, March 23-25, 2010.
2. Al-Madi, S.M., Al-Aidarous, O., Al-Dhubaib, T.A.,
AhmadHusain, H.A. and Al-Amri, A.D.: “I-Field Data
Acquisition and Delivery Infrastructure: Khursaniyah Field
Best in Class Practices,” SPE paper 128659, presented at
the SPE Intelligent Energy Conference and Exhibition,
Utrecht, The Netherlands, March 23-25, 2010.
3. Alhuthali, A.H., Al-Ajmi, F.A., Shamrani, S.S. and
Abitrabi, A.N.: “Maximizing the Value of the Intelligent
Field: Experience and Prospective,” SPE paper 150116,
presented at the SPE Intelligent Energy Conference and
Exhibition, Utrecht, The Netherlands, March 27-29, 2012.
4. Al-Mulhim, W.A., Al-Faddagh, H.A., Al-Shehab, M.A. and
Shamrani, S.S.: “Mega I-Field Application in the World,”
SPE paper 128837, presented at the SPE Intelligent Energy
Conference and Exhibition, Utrecht, The Netherlands,
March 23-25, 2010.
5. Yuen, B.B., Abdel Ghani, R., Al-Garni, S., Olukoko, O.
and Temaga, J.: “Utilizing New Proven Technologies in
Enhancing Geological Modeling and Reservoir Simulation
History Matching: Case Study of a Giant Carbonate
Field,” paper 152, presented at the 20th World Petroleum
Congress, Doha, Qatar, December 4-8, 2011.
BIOGRAPHIES
Bevan B. Yuen is a Petroleum Engineer
Consultant with the Reservoir
Simulation Division. He has built
reservoir simulation models for ‘Ain
Dar, Shedgum, Fazran, Abqaiq,
Khurais, Abu Jifan and Mazalij
production areas.
Aramco in 1999, Bevan worked
Prior to joining Saudi
S
for Amoco Canada, Computer Modeling Group, Canadian
Occidental and Qatar Petroleum.
from the University of Alberta, Edmonton, Alberta,
Canada, in 1979 and his M.S. degree in Petroleum
Engineering in 1982 and a MBA degree in 1990, both from
the University of Calgary, Calgary, Alberta, Canada.
Bevan’s interests are in complex well modeling, and
fracture and streamline simulation.
Dr. Olugbenga A. Olukoko is a
Petroleum Engineering Consultant in
the Reservoir Simulation Division,
where he has been carrying out
reservoir simulation studies to support
field development and reservoir
management activities. Prior to joining
in
SSaudi
di Aramco
A
i 2005,
200 he worked for Shell and Pan Ocean
Oil in Nigeria and the U.K. North Sea, holding various
positions between 1988 and 2005 in both reservoir and
petroleum engineering.
He received his B.S. and M.S. degrees in Mechanical
Engineering from the University of Lagos, Lagos, Nigeria,
in 1986 and 1988, respectively. Olugbenga then received
his Ph.D. degree in Computational Stress Analysis from
Imperial College, University of London, London, U.K., in
1992.
Dr. Joseph (Joe) Ansah is a Petroleum
Engineer Specialist with the Southern
Area Reservoir Management
Department at Saudi Aramco, where
he is involved in the development and
management of the fields in the
Khurais Complex. Previously, he
worked
k d for
f Halliburton
H llib t and WellDynamics in the areas of
smart well completions, hydraulic fracturing and
conformance technology, underbalanced drilling
technology, well testing and reservoir simulation. Prior to
that, Joe worked for Pennzoil E&P Company conducting
property evaluation and field development in Houston and
Midland, Texas.
He received his M.S. degree from the Gubkin Russian
State University of Oil and Gas, Moscow, Russia, and his
Ph.D. from Texas A&M University, College Station, Texas,
both in Petroleum Engineering.
Joe has authored and coauthored over 18 technical
papers in several industry journals and holds one U.S.
patent. He also served on the Society of Petroleum
Engineers (SPE) Editorial Review Committee from 2003 to
2009.
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33
Borehole Casing Sources for
Electromagnetic Imaging of Deep
Formations
Authors: Dr. Alberto F. Marsala, Dr. Andrew D. Hibbs and Prof. Frank Morrison
ABSTRACT
INTRODUCTION
The borehole to surface electromagnetic (BSEM) method and
cross-well electromagnetic (EM) method have been shown to
produce adequate subsurface electric current to image fluid
distribution at reservoir depth. These methods have proven to
be an efficient way to transmit EM signals deep into the reservoir, but their field deployment is potentially expensive and
logistically challenging. This is because several days of logging
conveyance inside a borehole is required to implement them.
The ability to efficiently transmit EM signals inside the
reservoir without a wellbore intervention would have a
tremendous potential impact in terms of cost reduction and
deployment opportunity for reservoir fluid mapping and monitoring, thanks to EM technologies already in the field. For
BSEM, a current electrode is placed inside the wellbore at
reservoir depth and a counter electrode is located adjacent to
the wellhead at the surface. The reservoir fluids are then imaged
through measurements of 1,000 EM receivers deployed at the
surface. An innovative approach described in this work is to
use a borehole casing as a way to introduce an electric current
into the earth at a considerable depth.
This new way to increase the current flowing in the subsurface at large offsets from the well is to combine a casing with
one or more remote surface electrodes located at a radial distance of approximately the casing depth. Contrary to common
expectations, a conducting casing is actually an advantage
when used in conjunction with an electric source.
Further, we analyze the performance of two specific variants
of a casing combined with remote electrodes, showing the capability to detect small electrical features at a depth of 2 km
out to greater than 2 km from the well. One of these source
configurations has the considerable advantage of not requiring
any well intervention for downhole operation. The model projections are compared to pilot surveys conducted in Saudi Arabia
and at two sites in the USA with well depths of up to 2,100 m.
Finally, we project the capability to detect small volumes of bypassed oil and establish the location of the oil-water boundary
at significant depth and offset from a vertical well.
Maximizing the recovery factor by means of detailed mapping
of hydrocarbon accumulations in the reservoirs is a key requirement for oil producing companies. This mapping is currently done by interpolation of accurate measurements of fluid
saturation at the wells’ locations, but a knowledge gap exists
in the inter-well volumes, where typically the only direct measurements available are density-based (seismic and gravity)
data. These technologies are not always effective in discriminating and quantifying the fluids inside the reservoirs (especially when the difference in fluid densities is small, such as
between oil and water). Consequently, when high electrical resistivity contrasts exist, as they do between hydrocarbons and
water, electromagnetic (EM) based technologies have the potential to map the distribution of the fluids, and if repeated in
time, to monitor their movement during the life of the field,
hundreds of meters or kilometers away from the wellbores.
The objective of an EM survey is to obtain resistivity and
induced polarization (IP) (or chargeability) maps of the reservoir, from which it is possible to calculate the saturating fluids
distribution. The specificity of the borehole to surface electromagnetic (BSEM) method, compared to cross-well EM surveys, is such that a BSEM survey requires only one surveyed
well to obtain an areal map of fluid distribution within a reservoir target layer kilometers away from the transmitting wellhead — up to 4 km, as demonstrated in Saudi Arabian pilot
projects1, 2. A cross-well EM survey, on the other hand, allows
higher resolution results, but it is limited to cross sections between two or more wells that are close enough for EM propagation — about 1 km in open holes and less in cased holes3.
The BSEM method in its time and frequency domain is an
evolution of the controlled source EM method, a surface-tosurface EM technique. The BSEM technology was first employed in the former Soviet Union at the end of the last
millennium and has been extensively improved in the recent
years in China, where it obtained positive results; a commercial protocol was subsequently developed and introduced by
the Bureau of Geophysical Prospecting (BGP)4-6. Successful
BSEM pilot studies have been reported by Saudi Aramco as
producing resistivity and IP images of oil-water contact
(OWC) at reservoir depth. In BSEM surveys, an electric current
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is injected into the earth via a source electrode using the configuration shown in Fig. 1. A downhole source electrode is
deployed sequentially at two or more depths inside the borehole
via a wireline, and the transmitted electrical circuit is completed
by a counter electrode located adjacent to the top of the well.
Part of the electric current flows from the downhole electrode
to the counter electrode through the casing, and the rest flows
within the earth, where it generates surface EM fields that are
characteristic of the electrical properties of the subsurface
around the well. The acquisition grid at the surface is composed
of an array of about 1,000 electric field sensors deployed up to
4 km around the EM transmitting wellhead. After data processing, the resulting maps reveal oil- and water-bearing zones in
the investigated reservoir layers.
Operating the downhole BSEM source electrode at two
depths and subtracting the respective datasets in post-processing is equivalent to deploying a single downhole dipole with
separation equal to the linear distance between the two downhole depths. Simulations for a 50 m dipole in an uncased well
show detectable change in both the surface electric fields and the
magnetic fields that occur at the earth’s surface up to 5 km in
cases where a resistive fluid is injected at a depth of 2,500 m7.
In a cased well, the concern is that the very high conductivity
of the steel pipe will act as an electrical short circuit between
the upper and lower electrodes of the BSEM source, resulting
in negligible current flow in the surrounding earth. A pilot test
of BSEM technology in a well with standard steel casing completion and production tubing, however, showed that this is
not the case2. A primary signal level of 100 μV/m was reported
Fig. 1. Conventional BSEM source configuration comprising an electrode at depth
within a borehole and a counter electrode at the earth’s surface, adjacent to the
borehole. The electric current within the ground is indicated by the lines and
arrows (the current paths are only shown on one side, but they flow with
approximately azimuthal symmetry all around the borehole).
at 1 km from the wellhead8. This field level was approximately
100,000 times greater than the achievable measurement noise
floor, opening the door to detecting those very small field
changes arising from fluid movement in the reservoir.
Next, we present the first calculations of the subsurface
current and the surface electric field produced by one or more
borehole electrodes operating from a cased well. We then project the subsurface currents and the surface electric fields for a
conventional BSEM configuration and two new source configurations, described herein for the first time. The two new
sources are designed specifically to exploit the capability of a
casing to inject current into a subsurface formation.
STATEMENT OF THEORY AND DEFINITIONS
Basic Properties of the Three Basic Borehole Casing Source
Configurations
The two new borehole source configurations are illustrated in
Figs. 2a and 2b. In Fig. 2a, a downhole electrode is deployed
at depth in the well in the same way as for a BSEM survey, but
instead of using a single electrode at the top of the well, the
surface electrode is implemented as a suite of four to 12 electrodes distributed in a partial or full circle of 1 km to 1.5 km
radius, approximately centered on the wellhead. Electric current flows down into the earth from this suite of electrodes, intercepting the casing along its entire length. Once it reaches the
casing, the current predominantly flows down the casing to the
downhole electrode — although in general some current intercepts the casing below the downhole electrode and flow upwards. For convenience, we term the source configuration in
Fig. 2a a deep casing source (DCS). The initial motivation for
using the DCS was to increase current flow in deep offset regions from the casing, which would extend the lateral detection range.
The second new borehole source configuration is similar to
that of the DCS except that instead of current flowing down
the casing to an electrode at depth, current flows up the casing
and is returned by a simple electrode connection to the top of
the casing, as illustrated in Fig. 2b. This configuration is
termed a top casing source (TCS) with the significant benefit
that all required equipment is deployed at the ground surface
instead of downhole. In the event the suite of surface electrodes is deployed in a complete circle, the DCS and TCS are
similar to a circular electric dipole9 except that they use a borehole casing energized at depth as the central electrode and no
attempt is made to equalize the currents in each surface electrode. It should be noted that the currents and fields produced
at any location by a conventional BSEM source are simply the
difference of those produced by the DCS and TCS, i.e., IBSEM =
IDCS- ITCS.
A simple way to capture the behavior of a casing source is
to note that at any point along a casing in contact with the
earth, the current divides into a component flowing in the
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Fig. 2. The two borehole source configurations for depth to surface EM surveys:
(a) with downhole electrodes, and (b) with the electrical connection at the top of
the casing. Arrows show the direction of current flow in the casing at the same
instant of the transmitted current waveform.
m depth. Above a value of Lc = 900, the injected current is relatively independent of the value of Lc. Figure 3 therefore illustrates a beneficial property of using a casing source in an EM
survey: the current injected into the formation can be relatively
independent of the formation resistivity. For example, if the
formation resistivity for the entire half of the subsurface varies
over the range from 25 Ω-m to 30 Ω-m, i.e., 20%, the Iinj in
the example of Fig. 3 varies by only 3.6%.
The variation of injected current along casings connected in
all three source configurations is illustrated in Fig. 4 for an
earth model of a conventional producing oil field. The model
comprises a low resistivity (2 Ω-m) surface layer to 1,300 m
depth, a layer of moderate resistivity (12 Ω-m) from 1,300 m to
1,500 m, a reservoir layer of thickness 15 m and resistivity 1
Ω-m, and a base layer of resistivity 5 Ω-m to a depth of 4,000 m.
The change in Iinj when crossing between each layer is immediately apparent. Importantly, despite the fact that the contact to
the casing is made at opposite ends, the current injected into
the reservoir for the TCS is 60% of that produced by the DCS.
The effect of adding an annulus of thickness 15 m and resistivity of 8 Ω into the reservoir layer of the model used to generate Fig. 4 is shown in Fig. 5. The center of the annulus is at a
distance of 500 m from the casing, and the data is plotted as a
percentage change to the current injected at reservoir depth
compared to the 50 m wide case. An annulus represents an extreme example of an anomaly because it intersects the radial
current in all directions. We see that there is less than 1%
change in the current in the reservoir layer up to an annulus of
width, 200 m for the DCS and 400 m for the TCS. This is an
important result because it shows that for many geologic features of interest, the profile of the injected current along the
casing is not significantly affected by the resistivity structure of
the earth, and can be calculated for the earth model alone in
the absence of a target body.
Detection of Subsurface Features via their Resistivity
Contrast
earth and a component flowing along the casing. For an infinitely long vertical casing in a uniform earth, the current flowing along the casing varies exponentially with the distance of
characteristic length Lc, given by Lc = √(Sc ρf) where Sc is the
casing conductance and ρf is the formation resistivity10. For
example, for a 20 cm diameter casing in earth of resistivity 20
Ω-m, Lc = 910 m.
The current injected into the formation, Iinj, is the spatial
differential of the current flow along the casing, i.e.,
The purpose of using a casing source is to extend the depth of
(1)
The casing dimensions and resistivity are generally stable
and well-defined, and so the primary parameter that affects Lc
is the formation resistivity. For example, the variation of casing current and injected current as a function of Lc is shown in
Fig. 3 at a depth of 1,500 m for a casing extending to a 1,600
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Fig. 3. Current flowing along a casing (Icas) and injected into a uniform earth at a
depth of 1,500 m (Iinj) as a function of casing conductance length. Casing length
is 1,600 m.
Fig. 4. Variation of injected current (mA) with depth (m) for the TCS, DCS and
BSEM sources. The subsurface model comprises four layers: 0 m to 1,300 m with
resistivity of 2 ȉ -m; 1,300 m to 1,500 m with resisitivity of 12 ȉ -m; 1,500 m to
1,515 m with resisitivity of 1 ȉ -m; 1,515 m to 4,000 m with resistivity of 5 ȉ -m;
and with casing to a depth of 1,600 m: (a) Injection current profile over all four
layers, and (b) Injected current in the reservoir layer (1,500 m to 1,515 m).
Fig. 6. Predicted TCS signals for a 100 m x 100 m wide region with center at 537
m indicative of a nonproducing zone in an earth model of the Marcellus shale: (a)
Contour plot of the surface E-field signal per unit current produced by the anomaly
for a TCS, and (b) Profile of the field in the x-direction (Ex) along the x-axis for
the TCS compared with profiles for a DCS, BSEM and conventional surface EM
source at the same casing location.
Fig. 5. Change in injected current into the reservoir (%) vs. the width (m) of an
annular resistive anomaly in the reservoir. The anomaly is centered at 500 m offset
from the casing. Reservoir resistivity is 1 ȉ -m and the anomaly resistivity is 8 ȉ -m.
EM investigation to the depth of typical hydrocarbon reservoirs.
A particular application is to image resistivity anomalies characteristic of hydrocarbon deposits. In Fig. 6, we calculate the
surface electric field signal produced by a 100 m wide x 100 m
long target in an earth model representative of the Marcellus
shale formation for a surface source electrode at x = 0, y = 500
m. The target is taken to be the difference between a mature
shale region containing producible hydrocarbons that is characterized by a resistivity of 35 Ω-m and an immature hydrocarbon
region of resistivity 10 Ω-m11. The depth to the top of the shale
is 1,890 m and the reservoir formation is 60 m thick.
The contour plot shows that the surface field produced by
the conducting anomaly is well aligned with the physical location of the anomaly. The field differences projected in Fig. 6 are
approximately 10 times higher than the minimum detectable
signal for advanced electric field sensors. For example, a sensor
noise level of 10-11 V/m can be achieved with less than 1 hour
of recorded signal averaging. The field profile in Fig. 6b shows
that both the TCS and DCS provide a dramatically improved
capability to detect and image hydrocarbon resistivity features
at reservoir depth compared to surface EM methods. As previously discussed, BSEM is equivalent to the difference of the TCS
and DCS, and so in this example it gives a much reduced signal.
As a final study, we calculate the resistivity change due to
the motion of an OWC in a 2,000 m deep reservoir, which is
characteristic of the geology in a Saudi Arabian super giant oil
field. We define two regions; an oil region with water saturation, Sw = 13% and resistivity 55 Ω-m, extending outwards as
an annular region from the well, which is bounded by an outer
water region with Sw = 50% and resistivity 4 Ω-m. The reservoir
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37
is 26 m thick. To make the signal differences easier to view,
Fig. 7 shows the surface field change for an oil to water boundary at three different distances from the well relative to the value
at 500 m. Importantly, the TCS produces a signal change
within a factor of approximately 25% of the DCS source.
Again, these fields are detectable using presently available
technology. For a time-lapse measurement, considerable signal
averaging is possible, and the TCS opens the door to long-term
monitoring without the cost of opening the well and providing
a wireline.
DESCRIPTION AND APPLICATION OF EQUIPMENT AND
PROCESSES
PRESENTATION OF DATA AND RESULTS
Figure 9 shows a comparison of the calculated and measured
surface electric field along a 2 km line from a well in a producing oil field in Montana. The two values of subsurface electrical resistivity as bounded by available well resistivity logs are
shown. The agreement between the predicted and measured
surface electric field is good, considering that other wells and
shallow connecting pipes were also present at the site. The
peak in the surface field at approximately 1,500 m from the
wellhead is caused by the receiver line passing very close to
one of the surface source electrodes, which were deployed on
Pilot Tests of EM Borehole Casing Sources
Two successful pilot tests of a BSEM source were conducted by
Saudi Aramco and the BGP, and results have been reported1, 8.
In 2013, three successful tests of the TCS were conducted in
North America: at a mature oil field, at a CO2 sequestration
site and at a geothermal test well. Figure 8 shows an example
of the electrical connection to the wellhead. A TCS is clearly
very easy to configure and has the obvious advantage that the
well does not need to be opened. It is also clearly suitable for
long-term monitoring and permanent installation.
Fig. 8. Photograph of a TCS connection to a wellhead for a pilot survey conducted
in 2013.
Fig. 7. Change in surface E-field for three positions of the boundary between oil
and water relative to the field for the same boundary at 500 m from a well in a
2,000 m deep reservoir: (a) DCS, and (b) TCS.
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Fig. 9. Comparison of the measured and calculated surface electric field produced
by a TCS as a function of radial distance from the wellhead. The source has a
partial ring of surface electrodes at a radius of 2 km.
a 1.5 km radius circle. The electric field at 1,800 m is 50
μV/m; approximately 10 times the value per unit currently
measured at the same distance in Saudi Arabia for a BSEM
source. Overall, Fig. 9 demonstrates that the TCS can be used
successfully in conditions relevant for hydrocarbon reservoir
monitoring.
CONCLUSIONS
Cross-well EM and BSEM are efficient ways to transmit EM
signals underground; they allow deep selective investigation of
reservoir layers, as demonstrated in recent surveys in Saudi
Arabia. Nevertheless, the costs and logistics linked to prolonged downhole deployment of electrodes in the borehole
could limit their fast deployment potential.
The innovative idea is to use wellbore casings as “guided
wave antennas” to induce EM signals from the surface, going
deep into the reservoir. The EM transmission occurs, connecting an electrode at the wellhead and a counter electrode buried
in the ground kilometers away. The EM signals, transmitted
through the reservoir, are then recorded at the surface by arrays of hundreds of receivers. The borehole casing provides a
distributed path to inject electrical current into the earth’s subsurface down to the reservoirs. Two new casing sources are
described that produce considerably larger signals than a conventional surface EM measurement and the recently introduced
BSEM method. One of these sources, the TCS, has the further
significant advantage that it requires no downhole equipment
of any kind. Importantly, the current injected into the subsurface by a casing varies as the differential of the current flow
along the casing, leading to beneficial results, in that the current injected at depth from a TCS can be almost as large for a
DCS and larger than for the BSEM source. Through data processing, the outcomes of those methods are resistivity, chargeability and fluid distribution maps of the investigated reservoir.
The goal is to map and monitor fluid distribution in the interwell volumes, supporting production optimization and recovery
increase from the hydrocarbon fields.
A pilot field test was recently concluded, demonstrating the
intrinsic safety of this EM transmitting method: At the wellhead,
we measured a harmless mere 0.36 V (relative to the ground)
on the casing connected to the source when transmitting EM
signals with the high power source (20A, 800 V) required to
energize a reservoir 4,000 m deep.
Numerical modeling of this innovative EM transmission
method validates its feasibility and potential to be deployed extensively in the field, even in time-lapse applications. Furthermore, an important issue for permanent monitoring is the
longevity of the system components in contact with the earth.
For a system that relies on injecting current, a particular concern
is degradation of the current injection electrodes. The TCS has a
particular advantage in this regard because only a simple metalto-metal connection is made at the top of the casing, compared to
the need to provide electrical coupling within the fluid environ-
ment inside the wellbore for all other downhole-based sources.
These developments considerably enhance the application of
EM methods to reservoir imaging. Both the TCS and DCS
sources have the capability to detect fluid movements in an
OWC using an array of electric and magnetic field sensors deployed at the surface. Because the TCS does not affect oil production, it could be considered for continuous operation, and
used to provide permanent real-time monitoring in producing
fields. When extensively field proven, this EM methodology will
have a tremendous potential impact in terms of cost reduction
and the potential to be deployed broadly for fluid distribution
mapping and monitoring in hydrocarbon fields.
ACKNOWLEDGMENTS
Aramco, GroundMetrics and Berkeley Geophysics Associates
for their support and permission to publish this article.
This article was presented at the SPE Annual Technical Conference and Exhibition, Amsterdam, The Netherlands, October
27-29, 2014.
REFERENCES
1. Marsala, A.F., Al-Buali, M., Ali, Z.A., Ma, S.M., He, Z.,
Biyan, T., et al.: “First Borehole to Surface Electromagnetic
Survey in KSA: Reservoir Mapping and Monitoring at a
New Scale,” SPE paper 146348, presented at the SPE
Annual Technical Conference and Exhibition, Denver,
Colorado, October 30 - November 2, 2011.
2. Marsala, A.F., Lyngra, S., Widjaja, D.R., Al-Otaibi, N.M.,
He, Z., Guo, Z., et al.: “Fluid Distribution Inter-Well
Mapping in Multiple Reservoirs by Innovative Borehole to
Surface Electromagnetic: Survey Design and Field
Acquisition,” IPTC paper 17045, presented at the
International Petroleum Technology Conference, Beijing,
China, March 26-28, 2013.
3. Marsala, A.F., Ruwaili, S.B., Ma, M.S., Al-Ali, Z.A., AlBuali, M.H., Donadille, J-M., et al.: “Crosswell
Electromagnetic Tomography: From Resistivity Mapping to
Interwell Fluid Distribution,” IPTC paper 12229, presented
at the International Petroleum Technology Conference,
Kuala Lumpur, Malaysia, December 3-5, 2008.
4. He, Z., Liu, X., Qiu, W. and Zhou, H.: “Mapping
Reservoir Boundary by Using Borehole Surface TFEM
Technique: Two Case Studies,” SEG-2004-0334 paper,
presented at the SEG Annual Meeting, Denver, Colorado,
October 10-15, 2004.
5. He, Z., Hu, W. and Dong, W.: “Petroleum Electromagnetic
Prospecting Advances and Case Studies in China,” Surveys
in Geophysics, Vol. 31, No. 2, March 2010, pp. 207-224.
6. He, Z., Zhao, Z., Liu, H. and Qin, J.: “TFEM for Oil
WINTER 2014
39
Detection: Case Studies,” The Leading Edge, Vol. 31, No.
5, May 2012, pp. 518-521.
7. Beyer, J.H., Smith, J.T. and Newman, G.: “Controlled
Source Electromagnetic (CSEM) Surveys to Monitor CO2,”
presentation at the West Coast Regional Carbon
Sequestration Partnership Annual Business Meeting, Lodi,
California, October 24-26, 2011.
8. Marsala, A.F., Hibbs, A.D., Petrov, T.R. and Pendleton,
J.M.: “Six-Component Tensor of the Surface
Electromagnetic Field Produced by a Borehole Source
Recorded by Innovative Capacitive Sensors,” SEG
Technical Program Expanded Abstracts, 2013, pp. 825-829.
9. Mogilatov, V. and Balashkov, B.: “A New Method of
Geoelectrical Prospecting by Vertical Electric Soundings,”
Journal of Applied Geophysics, Vol. 36, No. 1, November
1996, pp. 31-44.
10. Schenkel, C.J. and Morrison, H.F.: “Effects of Well
Casing on Potential Field Measurements Using Downhole
Current Sources,” Geophysical Prospecting, Vol. 38, No.
6, April 2006, pp. 663-686.
11. Schmoker, J.W. and Hester, T.C.: “Oil Generation
Inferred from Formation Resistivity – Bakken
Formation, Williston Basin, North Dakota,” Transactions
of the 13th SPWLA Annual Logging Symposium, June 14,
1989.
BIOGRAPHIES
Dr. Alberto F. Marsala has more than
20 years of oil industry experience. For
the last 8 years, he has been working
in Saudi Aramco’s Exploration and
ARC). Alberto started his career with
Eni and Agip,
Agip where he participated in several upstream
disciplines, including 4D seismic, reservoir characterization,
petrophysics, geomechanics, drilling and construction in
environmentally sensitive areas. Alberto worked on the
Technology Planning and R&D committee of Eni. He was
Head of Performance Improvement for the KCO joint
venture (Shell, ExxonMobil, Total and others) concerned
with the development of giant fields in the northern
Caspian Sea.
Alberto is now the Focus Area Champion for Deep
Diagnostic on the Reservoir Engineering Technology team
of EXPEC ARC, where he is pioneering innovative
technologies for advanced mud logging, logging while
drilling, and gravity and electromagnetic methods for
reservoir mapping and monitoring.
In 1991, Alberto received his Ph.D. degree in Nuclear
Physics from the University of Milan, Milan, Italy, and in
1996, he received an M.B.A. in Quality Management from the
University of Pisa, Pisa, Italy. He also holds a Specialization
in Innovation Management, received in 2001.
40
WINTER 2014
Dr. Andrew D. Hibbs is a leading
scientist and industrialist in the low
frequency electromagnetic sensing
community. He was one of the
founders of Quantum Magnetics
(QM), a pioneer in aviation security
technologies, which was acquired by
IInVision
Vi i Technologies
T h l i in 1998 and later by General Electric
in 2004. Prior to the acquisition of QM in 1998, Andrew
founded Quantum Applied Science and Research
(QUASAR) to develop bioelectric sensing systems, and he
has since spun out four other companies from QUASAR
covering diverse applications of EM sensing, including
EEG, ion channel measurements, lightning research, and
covert facilities detection and monitoring.
Among other pursuits, he is currently serving as Chief
Technology Officer of GroundMetrics Inc., which is
pursing electromagnetic applications in subsurface imaging
for resource exploration and extraction monitoring.
Prof. Frank Morrison is currently a P.
Malozemoff Professor Emeritus of
Mineral Engineering at the University
of California, Berkeley, and the
President of Berkeley Geophysics
Associates.
During his long and distinguished
career, Frank
F k has
h conducted research and done field and
laboratory work on a wide range of topics in applied
geophysics. Subjects have included numerical modeling of
electrical, IP and electromagnetic (EM) methods, field
studies of controlled source EM and self-potential methods
for geothermal exploration, ground and marine
magnetotellurics (MT) for petroleum exploration, audio
frequency MT profiling for mineral and groundwater
exploration, development of the theory and a full-scale
prototype for a unique single coil airborne EM system, and
theory and field systems for EM imaging between
boreholes.
He developed a new induction coil sensor for high
sensitivity measurements of low amplitude magnetic fields
and incorporated these sensors in the first portable
magnetotelluric system.
Frank was a co-founder of Electromagnetic Instruments,
which successfully commercialized the new MT system.
Working with Ed Nichols, he developed a controlled source
audio frequency MT system designed to enable a new
generation of groundwater exploration methods. This
system was transferred to Geometrics and is now marketed
as the Stratagem system.
For his accomplishments and for his role in translating
the results of many research projects into practical methods
for the exploration industry, Frank was elected an
Honorary Member of the Society of Exploration
Geophysicists (SEG) in 1999. He has published over 70
papers in recognized geophysical journals.
Frank received his Ph.D. degree in Engineering Science
from the University of California, Berkeley, CA, in 1967.
Laboratory Study on Polymers for
Chemical Flooding in Carbonate
Reservoirs
Authors: Dr. Ming Han, Alhasan B. Fuseni, Badr H. Zahrani and Dr. Jinxun Wang
ABSTRACT
As part of the screening process for chemical enhanced oil recovery (EOR), 18 polymer samples were screened as co-injectants in a surfactant-aided waterflood scheme. Due to their
higher viscosity, polymers improve waterflood sweep efficiency
and reduce the permeability of the rock matrix, therefore helping
to improve oil recovery. Aimed at a representative carbonate
reservoir in the Middle East, the polymer screening study focused
on polymer solubility and viscosity retention in high salinity
brines, equivalent to the reservoir parameters. The polymers
had to pass through a stringent screening process to meet the
harsh conditions encountered in the reservoir: high temperatures,
high salinities and the nature of the carbonate. Salinity effect
was studied in a range of brines that included shallow formation
water, produced water and connate water. Among the polymers
studied, six were found compatible and have been shortlisted
for EOR use. Based on rheological measurements and flow
curves, the concentrations of the polymers were determined to
achieve the target viscosity under reservoir conditions. Longterm stability and adsorption tests were conducted to ensure
the continued efficiency of the polymer when exposed to reservoir conditions. Oil displacement tests with a selected polymer
showed an increased oil recovery factor of 11% by polymer
flooding and 18% by surfactant polymer (SP) flooding. This
study demonstrates the potential application of polymers under extremely harsh reservoir conditions and their promise as
good additives for chemical flooding.
INTRODUCTION
Water soluble polymer is one of the key components in a
chemical enhanced oil recovery (EOR) process. It has been
used in processes of polymer flooding alone1, 2; polymer coinjection with surfactants, such as in surfactant polymer (SP)
flooding3-5 or alkaline SP flooding6-9; and as a preflush/
post-flush slug in surfactant or alkaline flooding.
Usually, two kinds of polymers have been used in the field: a
synthetic polymer classified as polyacrylamide and a biopolymer
known as xanthan. More than 90% of polymers consumed for
chemical EOR are the acrylamide type, whereas biopolymers
like xanthan are used in the field to only a very limited degree1.
The polymers are usually used at concentrations of 1,000 ppm
to 2,000 ppm in the flood water. Recently, higher polymer concentrations were required to achieve a given viscosity under
conditions of high salinity and high temperature10. Leonhardt
et al. (2013)11 presented field trial results for polymer flooding
with a biopolymer, schizophyllan, in a high salinity reservoir
(186 g/L total dissolved solids (TDS)). Also, some new synthetic polymers have received attention in recent research and
field applications, such as sulfonated polymers and sulfonic associative polymers12-15.
The role of a polymer in a chemical EOR process is primarily
to reduce the mobility ratio by increasing the viscosity of the
water16, although other mechanisms like viscoelastic effect are
involved17. It improves oil recovery beyond that achieved by
waterflooding or surfactant flooding alone by increasing the
contacted volume of the reservoir. In addition to increasing
water viscosity, polymer reduces the permeability of the reservoir matrix. This further lowers the effective mobility of the
injected fluid by increasing the residual resistance factor
(achieved with permeability reduction). When the permeability
is reduced, a lower polymer concentration can be used to gain
equivalent mobility control.
This study targeted a representative carbonate reservoir in
the Middle East. The challenges were the high salinity of the
reservoir brines and high reservoir temperatures. The evaluation of the polymers included tests of their compatibility with
various formation brines, a rheology study, assessment of the
impacts of salinity and temperature, and tests of the polymer’s
long-term stability. The results of this work demonstrate the
potential application of polymers under extremely harsh reservoir conditions and their promise as good additives for EOR in
carbonate reservoirs.
CHALLENGES OF CHEMICAL EOR IN CARBONATE
RESERVOIRS
Significant challenges exist in the development of chemical
EOR methods for carbonate reservoirs due to the complexity
of the rock mineral compositions, matrix pore structures, rock
surface properties, fracture densities, aperture and orientations,
as well as the different oil types18, 19. Carbonate rocks are a
class of sedimentary rocks composed primarily of carbonate
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41
minerals. The two major types are limestone, which is composed of calcite or aragonite (different crystal forms of
CaCO3), and dolostone, which is composed of the mineral
dolomite (CaMg(CO3)2). The nature of carbonate rocks differs
from that of sandstones, which are composed of quartz (SiO2)
grains cemented together with a variety of minerals. The lithology is described as a lime mud, foraminifera detrital carbonate20.
The detrital carbonate presents a bimodal pore system with a
pretty good permeability and porosity21. Despite its overall excellent flow characteristics, the bimodal system poses unique
challenges of recovering the oil remaining in the micropores.
Due to digenesis, carbonates tend to be more heterogeneous.
Natural fractures are more common in carbonate rocks than in
sandstones. The high density of such fractures and the resulting
high permeability zones present fluid flow uncertainty. In carbonate reservoirs, Super-K zones are areas dominated by high
linear flow; they can be high matrix flow zones or faults and
fractures22. The flow uncertainty in the presence of fractures
and high permeability zones tends to complicate the application
of EOR in such reservoirs.
The zones of high permeability are important conduits for
the flow of oil in the early production stages of the reservoir.
Subsequently, as the field matures, these same zones become
the conduits for excessive water production. In an EOR project
involving the injection of expensive fluids, care needs to be
taken to avoid the channeling of the slug through such conduits
to the producing well.
Harsh reservoirs are those with high brine salinity and hardness, and with high reservoir temperatures. Most field cases of
chemical flooding have been reported in moderate reservoirs.
Figure 1 shows the current limitation of chemical EOR technology on a salinity and temperature plot. The high salinity
and hardness of the reservoir brine degrade the chemicals’ effectiveness; polymers tend to precipitate when exposed to high
concentrations of divalent cations and will partition to the oil
phase at high salinities. High reservoir temperature also affects
the stability of the chemicals, especially polymers. Some major
reservoirs in the Middle East are in the high salinity and high
temperature region. This presents significant challenges in the
application of chemical EOR technologies.
A majority of the big carbonate fields are developed with a
peripheral water injection scheme, where water is injected on
the flanks of the reservoir for pressure maintenance23-25. The
objective of peripheral flooding is not only to maintain the
reservoir pressure but also to sweep the oil efficiently. In spite
of the carbonate’s complexity and the wide variation in rock
types and permeabilities, most of the big carbonate examples
have experienced semi-uniform flooding. For some major carbonate reservoirs with decent porosity and permeability, the
gravity/sudation force plays an important part in the depletion
process26 and the oil recovery can reach about 50% by means
of a peripheral waterflood. In peripheral water injection, the
well spacing is typically 0.5 km to 1 km. Such a large well
spacing leads to a delayed chemical flooding incremental recovery response. The incremental response can also be reduced
further as chemicals lose their effectiveness due to dispersion
and adsorption. For this reason, in-fill drilling to reduce well
spacing is usually required for chemical EOR implementation.
EXPERIMENTAL STUDY
Materials
Brines. Simulated field brines were synthesized for the study
based on the corresponding water analyses, including connate
water, seawater (injection water) and produced water. The detailed water analyses are presented in Table 1. All the simulated
brines were filtered through a 0.45 micron filter and deaerated
for test use.
Polymers. Several parameters have to be taken into account
when screening polymers to find the best candidates for SP
flooding in a Middle East carbonate reservoir. Good polymer
Seawater
(ppm)
Produced
Water (ppm)
Connate
Water (ppm)
Sodium
18,300
19,249
59,491
Calcium
650
4,360
19,040
2,110
938
2,439
n/a
n/a
n/a
Sulfate
4,290
1,299
350
Chloride
32,200
40,704
132,060
0
0
0
120
585
354
57,670
67,135
213,734
Ion
Magnesium
Potassium
Carbonate
Bicarbonate
TDS
Fig. 1. Challenge in chemical EOR for Middle East carbonate reservoirs.
42
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Table 1. Composition of field brines
candidates should meet the following requirements:
• Compatible with field brines.
• Effective at low concentration (0.1% to 0.3%).
• High viscosity (2 centipoise (cP) to 5 cP) over a wide
range of salinity at 95 °C to 100 °C.
• Long-term stability (<50% viscosity loss over 6 months at
Polymer Type
Polymer
Form
Active (%)
PST01
HPAM
Powder
86.92
PST02
Sulfonated PAM
Powder
91.80
PST03
Sulfonated PAM
Powder
92.16
PST04
Sulfonated PAM
Powder
87.70
PST05
Biopolymer
Powder
88.84
PST06
Biopolymer
Powder
89.69
PST07
Biopolymer
Powder
91.31
PST08
Biopolymer
Powder
86.38
PST09
Modified PAM
Powder
88.17
PST10
Modified PAM
Powder
88.49
PST11
Associating PAM
Powder
93.62
PST12
Associating PAM
Powder
91.06
PST13
High Molecular
Weight PAM
Powder
88.04
PST14
HPAM
Powder
90.54
PST15
HPAM
Powder
92.37
PST16
HPAM
Powder
87.45
PST17
Sulfonated PAM
Powder
93.06
PST18
Sulfonated PAM
Powder
93.30
Polymer
95 °C to 100 °C).
• Low adsorption onto formation rock (<1 mg/g-rock).
• Available in large quantities.
• Easily handled in the field.
A total of 18 polymer samples were tested, including polyacrylamide, sulfonated polyacrylamide and associative polyacrylamide, as well as polysaccharides like xanthan gum,
scleroglucan and Welan gum. The chemicals listed in Table 2
were renamed in this article to avoid commercialism and for
confidential concerns.
Rheological Measurement. A MCR 301 rheometer from Anton Paar, Austria, was used for rheological measurement. The
instrument enables the measuring of various viscoelastic properties, including flow curve, creep and viscoelasticity. It is
equipped with concentric cylinder geometry having shear rates
ranging from 0.01 s-1 to 1,000 s-1.
Viscosity was also measured using DV II+Pro, a Brookfield
viscometer made in the U.S., for preliminary screening. The
spindle used was S18. The temperature was set at 25 °C.
Polymer Concentration. The polymer concentrations were
verified by carbon analysis using a total organic carbon (TOC)
analyzer made by Shimadzu, Japan.
Core Plugs. Natural core plugs with a 3.81 cm (1½”) diameter
were selected for the coreflooding tests. The diameter and
length of the plugs ranged from 3.7 cm to 3.8 cm and from 3.6
cm to 4.6 cm, respectively. The air permeability, pore volume
and porosity of the core plugs were measured by routine core
analysis.
The dried core plug samples were evacuated and saturated
with the simulated formation brine. The saturated plugs were
immersed in the simulated formation brine to establish ionic
equilibrium between the rock constituents and the formation
brine. Brine permeability was then measured using the simulated
Table 2. Polymers collected for screening
Core
Num.
Length
(cm)
Diameter
(cm)
Porosity
(fraction)
Air
Permeability
(md)
Pore
Volume
(cm3)
Brine
Permeability
(md)
Coreflooding
Test
1
4.95
3.785
0.188
633
10.471
501
Polymer Adsorption
2
4.44
3.798
0.168
513
8.458
441
Polymer Adsorption
3
4.42
3.768
0.275
445
13.566
315
Adsorption of
Surfactant and
Polymer
4
4.64
3.798
0.165
428
8.664
304
Adsorption of
Surfactant and
Polymer
5
4.69
3.785
0.121
175
6.392
N/A
Polymer Flooding
6
3.61
3.790
0.232
122
3.94
N/A
SP Flooding
7
4.62
3.800
0.214
134
6.73
N/A
SP Flooding
Table 3. Petrophysical properties of core samples for coreflooding tests
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43
formation brine. Table 3 lists the detailed porosity, pore volume, air permeability and brine permeability for the test samples.
Seawater
Produced
Water
Connate
Water
Remark
PST01
C
C
C
Declined
PST02
A
A
A
Excellent
PST03
A
A
A
Excellent
PST04
A
A
A
Excellent
Polymer
Coreflooding Tests. The FDES-645 coreflooding apparatus,
made by Coretest System, USA, was used in this study. The
schematic setup is shown in Fig. 2. Injection pressure, confining pressure, pore pressure, differential pressure and flow rate
were recorded automatically during the test. The specific test
procedures are described later for the experiments investigating dynamic adsorption and oil displacement.
PST05
B
A
A
Excellent
PST06
B
B
B
Good
EVALUATION OF POLYMERS IN BULK SOLUTIONS
PST07
C
D
D
Declined
PST08
C
C
D
Declined
PST09
A
A
A
Excellent
PST10
A
C
C
Declined
PST11
A
A
A
Excellent
PST12
D
D
D
Declined
PST13
C
C
C
Declined
PST14
A
A
A
Excellent
PST15
A
A
A
Excellent
PST16
A
A
A
Excellent
PST17
A
A
A
Excellent
PST18
A
A
A
Excellent
Compatibility with Brines
Studies of the compatibility between reservoir fluids and polymers are in many cases critical to predict whether the polymer
can be applied successfully. This is because the efficiency of a
polymer solution will be greatly reduced if there are precipitation and insoluble particles when the solution encounters
incompatible brines. Therefore, compatibility tests were conducted for all the polymers with respect to field brines.
Polymer solutions with 2,000 ppm active component were
prepared in different field brines. The solutions were sealed
and put in an oven at 95 °C, then observed visually for evidence
of precipitation. The results were recorded by compatibility
codes of A: clear solution; B: slight hazy solution; C: hazy solution; and D: precipitation, Fig. 3. Table 4 illustrates the results
of the compatibility studies with different field brines. Based
on this study, seven out of the 18 polymers were eliminated
from the candidate list.
Table 4. Compatibility codes showing polymer compatibility with field brines
Viscosities of Polymers in Brines
The viscosity of a polymer is one of the critical parameters to
evaluate its effectiveness in a given reservoir environment,
especially one with high salinity and temperature. A polymer’s
viscosity depends on its chemical structure (type, component
and molecular weight) and its configuration (coil and rod) in
brine. Figure 4 shows the viscosities of the candidate polymers in
different brines (seawater, produced water and connate water).
With this test, we eliminated four more polymers having low
viscosity due to low molecular weights, although these polymers
presented a strong potential to tolerate high salinity and high
temperature environments.
Fig. 2. Schematic setup for coreflooding tests.
Fig. 3. Compatibility codes.
44
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Rheological Characteristics
Rheological study of the deformation and flow of matter under
the influence of an applied stress provides insight into the deformation/flow behavior of the material and its internal structure.
The rheological properties of polymer solutions play a very important role in characterizing the polymers and determining
their likely performance and effectiveness.
Polymer solutions are known to exhibit non-Newtonian,
shear-thinning fluid behavior. In other words, the viscosity is
dependent on the shear rate. Actually, the viscosity-shear rate
range. PST02, in a coil configuration, also showed shear-thinning
behavior with an increasing shear rate.
The Carreau model was used to cover overall performance
in a full range of shear rates. In the Carreau model, the viscosity function depends on the shear rate, Eqn. 2.
Fig. 4. Viscosity of the test polymers in different brines.
relationship exhibits a Newtonian behavior at low shear rates
and a power-law behavior at high shear rates. These properties
can usually be determined in the laboratory using a rheometer.
This fluid performance is critical for assessing the field application of a polymer solution because the polymer solution
presents different viscosities on the surface, at the perforations
and at different locations during its propagation in the reservoir.
This phenomenon of differing viscosity is based on the fact
that the configuration of a polymer changes with the velocity.
The shear rate in the rock matrix is basically dependent on the
flow velocity and rock properties, as seen in Eqn. 1.
(1)
where is shear rate, C is constant, ȗ is velocity, k is permeability, and is porosity.
In this work, we demonstrate the characteristics of two
promising polymers: a synthetic polymer (PST02) and a polysaccharide (PST06). Figure 5 shows the flow curves of PST02
and PST06 at 2,000 ppm concentration in produced water at
25 °C. PST06 is a biopolymer in a rod-like configuration, leading to a high viscosity at a low shear rate range, and significant
shear-thinning behavior and low viscosity at a high shear
Fig. 5. Flow curves of PST02 and PST06 solutions in produced water.
(2)
where 0 is zero shear viscosity, is infinite viscosity, (n-1) is
slope shear thinning, and is rotational relaxation time,
which is the inverse of the critical shear rate. The critical shear
rate is the shear rate at which there is a transition from Newtonian to shear-thinning behavior. The rheological parameters
in Table 5 were extracted from the flow curves. Figure 6
demonstrates the fit of the model with the actual data. These
parameters can be used to estimate the viscosity at any shear
rate, including zero-shear viscosity and infinitive viscosity. It is
important to simulate the viscosity for a numerical reservoir
simulator for a chemical EOR process when polymer solution
propagates in the deep reservoir.
The variation of the viscosity of a polymer solution, , as a
function of concentration, c, can be described as:
(3)
Parameter
PST02
PST06
h0
20.3 cP
6,230 cP
h3
6.59 cP
2.06 cP
x
3.16 s
11.63 s
n-1
0.46
0.81
Table 5. Rheological parameters of PST02 and PST06 extracted from the flow
curves
Fig. 6. Simulation of flow behavior of 0.2% PST06 solution in produced water
using the Carreau model matched with real data.
WINTER 2014
45
in which s represents solvent viscosity, k1 and k2 are constants,
and [] is intrinsic viscosity. The is generally referred to as
zero-shear viscosity, which is determined by a flow curve. The
[] and the overlap concentration can be obtained by flow curves.
In a very low concentration range, [] can be determined by
extrapolation of sp/c to c->0 as:
(95 °C). The polymer solutions were taken from the oven
periodically to measure the viscosity retention. Figure 7 shows
that some polymers can withstand 6 months under the given
conditions of 95 °C and an anaerobic environment, i.e., they
retain sufficient viscosity. With this test, the number of potential polymers was reduced to four.
Interaction with Selected Surfactants
(4)
The [] is related to the size (gyration radius) of a single
molecule in the solution, indicating the capacity to increase the
viscosity. In general, at certain conditions, the polymer molecule weight, M, can be determined by the following relationship:
(5)
in which k is a constant, and a is a constant between 0.5 to 1.5.
The overlap concentration, C*, is an important parameter
in describing a polymer solution. In polymer solution theory,
polymer solutions are divided into regimes: dilute, semi-dilute
and highly concentrated. The critical concentration between
the dilute regime and the semi-dilute regime is called the overlap concentration. It corresponds to the solution where polymer coils begin to touch one another throughout the solution.
Table 6 summarizes the values of C* and [] for two polymers in different brines. Usually, polymer concentration is selected in a semi-dilute regime. Therefore, the concentration
used for PST02 should be much higher than that for PST06. In
this regard, polysaccharides with a rod-like configuration in
solution present advantages over synthesized polymers. This is
consistent with the literature.
Because some polymers were screened as co-injectants for a SP
flooding scheme, the compatibility of the polymers with selected surfactants was an additional criteria for the polymers.
Although polymers and surfactants are added to the water for
their independent functions, some interactions may arise. Such
interactions when a polymer and a surfactant are present together may lead to significant changes in the system properties,
which are considered either beneficial or undesirable, depending
on the prevalent conditions.
Formulations of the promising polymers and surfactants
were developed by changing and tuning the concentrations of
the chemicals and environments to get better SP compatibility,
lower interfacial tension (IFT), higher viscosity, lower adsorption and eventually higher oil recovery. Table 7 illustrates the
properties of some formulations studied. This led to the elimination of polymer in formulation #8, which is obviously incompatible with a selected amphoteric surfactant.
EVALUATION OF POLYMERS IN POROUS MEDIA
Long-term Stability
To be effective, polymer solutions must remain stable for a
long time at reservoir conditions. Polymers are known to be
sensitive to chemical and thermal degradations, especially in
the presence of oxygen and oxidizing agents at high temperature.
It is believed that the reservoir is an anaerobic environment.
Therefore, the polymer solution is expected to be free of oxygen during its propagation in the reservoir. The polymer solutions were prepared by replacing oxygen using nitrogen for 2
hours before putting them in the oven at reservoir temperature
Brine
Fig. 7. Long-term stability of three polymer solutions in seawater in an anaerobic
environment at 95 °C.
PST02
PST06
C* (ppm)
[h] (mL/g)
C* (ppm)
[h] (mL/g)
Seawater
1,700
2,352
268
14,909
Produced
2,323
1,722
218
18,348
Connate
5,405
740
-
-
Table 6. Overlap concentration, C*, and intrinsic viscosity, [n], of PST02 and PST06
46
WINTER 2014
Formulation
Compatibility
(Compatibility Code)
#1
Phase Behavior
(Winsor Type)
IFT at 90 °C
(dynes/cm)
Viscosity (cP)
25 °C
95 °C
25 °C
95 °C
25 °C
95 °C
Simul.
Eq.
A
A
I
I
45.8
11.5
0.00606
0.0096
I
I
16.9
4.84
0.00464
0.00769
#2
B
B
#3
B
C
I
I
20.0
5.62
0.337
0.479
#4
B
B
I
I
19.2
5.45
/
0.0595
#5
A
B
I
I
21.9
5.49
/
0.0461
I
I
59.6
6.7
0.0279
0.0549
#6
A
B
#7
A
B
I
I
26.2
8.96
0.04520
0.0479
#8
A
C
I
I
20.2
5.71
/
0.0215
#9
B
B
I
I
31.5
7.75
0.00939
0.0369
I
I
50.0
8.75
0.06250
0.0661
#10
A
B
#11
A
B
I
I
22.5
5.29
0.03650
0.0455
#12
A
B
I
I
131.0
15.0
0.03370
0.0667
#13
A
B
I
I
27.6
6.66
0.00740
0.0382
Table 7. Properties of study formulations
The polymer selected for further study, PST02, is a sulfonated
polymer. The main objectives were to evaluate its dynamic adsorption or retention, the injectivity, and its oil recovery potential in porous media with a carbonate nature. In some cases, a
selected amphoteric surfactant was used as a co-injectant to
study the performance of the polymer in the presence of the
surfactant, which could occur in a SP scheme.
Dynamic Adsorption
Two groups of dynamic adsorption tests were performed, including two tests for polymer adsorption and two tests for SP
adsorption. The concentration of the polymer solution was
2,000 ppm. In the SP mixture, both surfactant and polymer
concentrations were 2,000 ppm, making the total chemical
concentration of 4,000 mg/L. Each injected chemical slug was
5 pore volumes (PVs) in size. The injection of the chemical slug
was preceded by a seawater flooding and followed by post-seawater flooding. All tests were conducted at a constant flow
rate of 0.5 cm3/min with a net confining pressure of 1,300 psi
and pore pressure of 3,100 psi at 100 °C.
The concentrations of the chemical collected in the effluents
were analyzed to calculate the amount of chemical produced
during the coreflooding test, which was then used to determine
the amount of chemical adsorbed onto the rock surface. Titration and TOC methods were used for the concentration analysis. For the case of SP mixture injection, the titration and TOC
analyses were performed on alternative effluent samples to
determine the surfactant concentration and the total SP concentration, respectively.
The amount of chemical lost in the core sample can be
determined by subtracting the total chemical produced from
the total chemical injected based on the mass balance. The as-
sumption was that the chemical is uniformly adsorbed onto the
rock surface when the amount of produced chemical is negligible at the end of post-seawater flooding. The chemical adsorption per unit rock weight was then calculated from the total
amount of chemical loss during the coreflooding test and the
dry weight of the core sample before it was saturated with the
formation brine. The total mass of the injected chemical is the
product of the total volume and the concentration of the injected chemical slug. The total mass of the produced chemical
is the sum of the chemical mass in each collecting tube, which
was similarly calculated as the product of volume and concentration in each tube.
Two polymer injection tests were conducted. Figure 8 shows
the effluent polymer concentration fraction and the ratio of the
effluent polymer concentration (C) to the injected polymer
concentration (Co) as a function of fluid injected. The plot starts
from the beginning of the chemical slug injection and ends when
effluent concentration is negligible. The dots in the figure are
experimental data and the solid line is a smoothed curve. From
the analyzed effluent polymer concentration and the total amount
of injected polymer, the adsorptions of polymer on the rock
surfaces were determined based on material balance, to be
0.121 and 0.133 mg/g-rock for the two tests, respectively.
A mixture of surfactant and polymer was injected in two
tests to investigate the competitive adsorption between polymer and surfactant. Figure 9 plots the effluent total chemical
concentration fraction and the surfactant concentration fraction as functions of fluid injected for a test. Both concentration
fractions were calculated based on the injected total chemical
concentration of 4,000 ppm. The total SP adsorptions were
0.161 and 0.151 mg/g-rock for the two tests, respectively. The
adsorptions of surfactant in these two tests were 0.0834 and
0.0872 mg/g-rock. The adsorptions of polymer were then
WINTER 2014
47
Fig. 10. Oil recovery curve of polymer flooding.
Fig. 8. Profile of effluent polymer concentration.
Fig. 11. Oil recovery curve of SP flooding.
Fig. 9. Profiles of effluent polymer and surfactant concentrations.
calculated by subtracting the surfactant adsorption from the
total SP adsorption, which were determined to be 0.0776 and
0.0638 mg/g-rock for the two tests, respectively.
Table 8 summarizes the results of all these four dynamic adsorption tests. Comparing the results of these two tests, it can
be seen that the adsorption of polymer was evidently reduced
when surfactant and polymer were co-injected. The total SP
adsorption in the case of chemical co-injection was very close
to the adsorption of polymer when only polymer was injected.
Oil Recovery Potential
Two plug samples were prepared for tertiary oil recovery tests
by polymer flooding and SP flooding, respectively. Initial water
saturation was established by centrifuge method using dead
crude oil. The samples were then aged for four weeks before
the start of the oil recovery tests. Waterflooding was conducted
Test
Num.
Ambient
Porosity
(fraction)
Ambient Air
Perm.
(md)
Brine
Perm.
(md)
Injected
Chemical
Total
Adsorption
(mg/g-rock)
Surfactant
Adsorption
(mg/g-rock)
Polymer
Adsorption
(mg/g-rock)
1
0.188
633
501
Polymer
0.121
N/A
0.121
2
0.168
513
441
Polymer
0.133
N/A
0.133
3
0.275
445
315
Mixture of
Surfactant
and Polymer
0.161
0.0834
0.0776
4
0.165
428
304
Mixture of
Surfactant
and Polymer
0.151
0.0872
0.0638
Table 8. Summary of dynamic adsorption results
48
It indicated that the adsorption sites of the rock surface were
competitively occupied by the polymer and surfactant.
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using seawater at the constant flow rate of 0.5 cm3/min, net
confining pressure of 1,300 psi, pore pressure of 3,100 psi and
a temperature of 100 °C. A chemical slug of 0.6 PV was injected
when the waterflooding oil production was negligible, and
then a post-waterflooding was followed.
The cumulative oil recovery as a function of fluid injected
for Test 5 has been plotted in Fig. 10. Waterflooding oil recovery
was 61% original oil in place (OOIP). Then 0.6 PV of 3,000
ppm polymer solution was used in this test and the tertiary oil
recovery reached 11% OOIP.
Figure 11 presents the oil displacement coreflooding experiment results using a selected formulation composed of surfactant and polymer. Waterflooding oil recovery was about 72%,
and tertiary oil recovery by surfactant and polymer was 18%.
These results indicate that significant tertiary oil recovery can
be achieved by the injection of a chemical slug composed of
the selected SP combination.
CONCLUSIONS
1. Eighteen different types of polymers were evaluated
through a stringent sequential screening process to study
the feasibility of polymer flooding or SP flooding for a
representative Middle East carbonate reservoir. Three
polymers among 18 candidates met the critical requirements of compatibility with brines, viscosity, long-term
stability, and compatibility with the selected surfactant
under hostile conditions.
2. A synthetic sulfonated polyacrylamide presented very low
dynamic adsorption on the carbonates in the range of 0.15
mg/g-rock. When the polymer was co-injected with a
selected amphoteric surfactant, the portion of the polymer
adsorption was in the range of 0.06 to 0.08 mg/g-rock due
to the competitive occupation of rock sites by polymer and
surfactant. These phenomena indicate that the polymer can
be successfully applied in carbonate reservoirs owing to the
low adsorption. This allays a concern questioning if an
anionic polymer could be used for carbonates with positive
surface charge.
3. The oil displacement tests showed that an incremental oil
recovery of 11% OOIP was achieved by polymer flooding
using 3,000 ppm of the synthetic sulfonated polyacrylamide
in tertiary recovery mode at reservoir conditions. For SP
flooding, the incremental oil recovery reached 18% OOIP.
These results indicate the great potential presented by
incremental oil recovery via polymer-related chemical
flooding.
ACKNOWLEDGMENTS
The authors would like to thank Saudi Aramco’s EXPEC Advanced Research Center for permission to publish this article.
The authors are grateful to the Chemical EOR team members
for their continued support and involvement in this study.
This article was presented at the SPE EOR Conference at Oil
and Gas West Asia, Muscat, Oman, March 31 - April 2, 2014.
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Huabin, L. and Xiahong, G.: “An Alkaline/Surfactant/
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Annual Technical Conference and Exhibition, New
Orleans, Louisiana, September 27-30, 1998.
8. Chang, H.L., Zhang, Z.Q., Wang, Q.M., Xu, Z.S., Guo,
Z.D., Sun, H.Q., et al.: “Advances in Polymer Flooding
and Alkaline/Surfactant/Polymer Process as Developed and
Applied in the People’s Republic of China,” Journal of
Petroleum Technology, Vol. 58, No. 2, February 2006, pp.
84-89.
9. Pandey, A., Beliveau, D., Corbishley, D.W. and Kumar,
M.S.: “Design of an ASP Pilot for the Mangala Field:
Laboratory Evaluations and Simulation Studies,” SPE
paper 113131, presented at the SPE Indian Oil and Gas
Technical Conference and Exhibition, Mumbai, India,
March 4-6, 2008.
10. Pope, G.: “Recent Developments and Remaining
Challenges of Enhanced Oil Recovery,” Journal of
Petroleum Technology, July 2011, pp. 65-68.
WINTER 2014
49
11. Leonhardt, B., Santa, M., Steigerwald, A. and Kaeppler,
T.: “Polymer Flooding with the Polysaccharide
Schizophyllan – First Field Trial Results,” paper presented
at the 17th European Symposium on Improved Oil
Recovery, St. Petersburg, Russia, April 16-18, 2013.
12. Han, M., Xiang, W., Zhang, J., Jiang, W. and Sun, F.:
“Application of EOR Technology by Means of Polymer
Flooding in Bohai Oil Fields,” SPE paper 104432,
presented at the International Oil and Gas Conference
and Exhibition, Beijing, China, December 5-7, 2006.
13. Rashidi, M.: “Physico-Chemistry Characterization of
Sulfonated Polyacrylamide Polymers for Use in Polymer
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Norway, June 2010.
14. Seright, R.S., Fan, T., Wavrik, K., Wan, H., Gaillard, N.
and Favero, C.: “Rheology of a New Sulfonic Associative
Polymer in Porous Media,” SPE paper 141355, presented
at the SPE International Symposium on Oil Field
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15. Levitt, D., Klimenko, A., Jouenne, S., Chamerois, M. and
Bourel, M.: “Overcoming Design Challenges of Chemical
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SPE paper 164241, presented at the SPE Middle East Oil
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10-13, 2012.
16. Sorbie, K.S.: Polymer-Improved Oil Recovery, Springer,
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19. Manrique, E.J., Muci, V.E. and Gurfinkel, M.E.: “EOR
Field Experience in Carbonate Reservoirs in the United
States,” SPE paper 100063, presented at the SPE/DOE
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20. Han, M., Al-Sofi, A.M., Fuseni, A.B., Zhou, X. and
Hassan, S.F.: “Development of Chemical EOR
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Carbonate Reservoir,” IPTC paper 17084, presented at
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21. Clerke, E.A.: “Permeability, Relative Permeability,
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paper 105259, presented at the SPE Middle East Oil and
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Gas Show and Conference, Manama, Bahrain, March 1114, 2007.
22. Olarewaju, J., Ghori, S., Fuseni, A.B. and Wajid, M.:
“Stochastic Simulation of Fracture Density for
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23. Malinowski, R.: “Water Injection, Arab-D Member,
Abqaiq Field, Saudi Arabia,” SPE paper 85, presented at
the SPE Middle East Regional Meeting, Dhahran, Saudi
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Bahrain, November 16-19, 1991.
25. Kiani, M., Kazemi, H., Ozkan, E. and Wu, Y-S.: “Pilot
Testing Issues of Chemical EOR in Large Fractured
Carbonate Reservoirs,” SPE paper 146840, presented at
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Denver, Colorado, October 30 - November 2, 2011.
26. Pham, T.R. and Al-Shahri, A.M.: “Assessment of Residual
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paper 68069, presented at the SPE Middle East Oil Show,
Manama, Bahrain, March 17-20, 2001.
BIOGRAPHIES
Dr. Ming Han works in Saudi
Aramco’s Exploration and Petroleum
Research Center (EXPEC ARC) as a
Petroleum Engineering Specialist in
chemical enhanced oil recovery. Before
joining Saudi Aramco in 2007, he
Offshore Oil Corporation
worked for China National
N
(CNOOC), where he was Lead Engineer in Oil Field
Chemistry at the CNOOC Research Center working to
implement an offshore polymer flooding project. For more
than 10 years of his career, Ming worked for the Research
Institute of Petroleum Exploration and Development
(RIPED) in China as a Research Engineer, conducting
laboratory studies and field pilots in water shutoff, profile
modification, polymer flooding and chemical flooding. He
also served Hycal Energy Research in Canada as a
Research Engineer.
In 1982, Ming received his B.S. degree in Chemistry
from Jilin University, Changchun, China. He received his
M.S. degree from the University of Paris VI, Paris, France,
and his Ph.D. degree from the University of Rouen, MontSaint-Aignan, France.
Ming is a member of the Society of Petroleum Engineers
(SPE) and the American Chemical Society (ACS).
Alhasan B. Fuseni joined Saudi
Aramco in 2006 and is a member of
the Chemical Enhanced Oil Recovery
(EOR) team of the Exploration and
ARC). Prior to joining Saudi Aramco,
he worked for the King
Fahd University of Petroleum and
K
Minerals (KFUPM) Research Institute as a Research
Engineer, and for Hycal Energy Research, Calgary, Canada,
as an EOR Technologist. Alhasan has taught an in-house
course on core flooding applications in chemical EOR at
EXPEC ARC, and he teaches the chemical EOR section of
the course on EOR at Saudi Aramco’s Upstream
Professional Development Center. He has authored and
coauthored several papers in petroleum engineering and is
currently serving as a reviewer for Elsevier’s Journal of
Petroleum Science and Engineering.
Alhasan received both his B.S. and M.S. degrees in
Petroleum Engineering from KFUPM, Dhahran, Saudi
Arabia, in 1985 and 1987, respectively.
Badr H. Zahrani works in Saudi
Senior Laboratory Technician in
chemical enhanced oil recovery (EOR).
He joined Saudi Aramco in 2006 as a
trainee,
and
he went on to work as an
i
d then
h in
i 2008
2
Operator in the Safaniya Offshore Producing Department.
In 2009, Badr was transferred to EXPEC ARC. His
expertise is in the evaluation of EOR chemicals, and he has
been involved in many research and service projects.
In 2008, Badr finished his training in the Industrial
Training Center (ITC) in Ras Tanura, Saudi Arabia.
Badr is a member of the Society of Petroleum Engineers
(SPE).
Dr. Jinxun Wang works at Saudi
Petroleum Engineer in the chemical
enhanced oil recovery focus area of the
Reservoir Engineering Technology
Division.
Saudi Aramco, he worked with
Division Before joining
join
Core Laboratories Canada Ltd. as a Project Engineer in
their Advanced Rock Properties group. Jinxun’s experience
also includes 10 years of research and teaching reservoir
engineering at petroleum universities in China.
Jinxun received his B.S. degree from the China
University of Petroleum, his M.S. degree from the
Southwest Petroleum Institute, China, and his Ph.D. degree
from the Research Institute of Petroleum Exploration and
Development, Beijing, China, all in Petroleum Engineering.
He received a second Ph.D. degree in Chemical Engineering
from the University of Calgary, Calgary, Alberta, Canada.
Jinxun is a member of the Society of Petroleum
Engineers (SPE) and the Society of Core Analysts (SCA).
WINTER 2014
51
Sweet Spot Identification and Optimum
Well Planning: An Integrated Workflow to
Improve the Sweep in a Sector of a Giant
Carbonate Mature Oil Reservoir
Authors: Dr. Ahmed H. Alhuthali, Abdullah I. Al-Sada, Abdullah A. Al-Safi and Mohammed T. Bouaouaja
ABSTRACT
This study illustrates a comprehensive integrated approach to
identifying the potential locations for future development in
one sector of a giant carbonate mature oil reservoir. The approach uses various data from several sources, including
reservoir surveillance, production performance, geological
interpretation and numerical simulation data, and cohesively
combines them to yield an informed decision when assessing
field development and management. The study area has been
under peripheral waterflood for more than 50 years and is
dominated by heterogeneity related to fracture corridors, a
high permeability zone and reservoir zonation. These features
have led to a preferential and uneven propagation of water
flow, which results in unswept oil bearing spots after production using the existing well’s layout and configuration.
The reservoir management team has developed an integrated
workflow to address these challenges by using several reservoir
engineering methods and models, including water encroachment,
reservoir opportunity index (ROI), fractional flow calculation,
remaining volumetric and water flow paths. The designed workflow consists of first creating derived attributes that describe
these models and then filtering the sector area using those attributes to define the sweet spots. The selection and prioritization
of the defined sweet spots are subsequently supported by available reservoir surveillance and production data. The scarcity of
reservoir surveillance and production data in some areas of the
sector motivated the reservoir management team to stretch the
limits by capitalizing on logs from the gas wells penetrating the
shallower oil reservoirs. The open hole logs of these wells
recorded a thicker oil column than the column pre-estimated
using the existing surveillance data.
As a result of these efforts, a development plan has been
designed to ensure reserves depletion in the identified sweet
spots by drilling new wells or sidetracking existing wells. Despite
the reservoir’s level of maturity, simulation forecasts indicate
that the area of interest has a lot of potential to sustain a high
production rate.
INTRODUCTION
The area of interest is located in the central part of a carbonate
52
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oil field in Saudi Arabia. The subject reservoir has been penetrated by hundreds of wells, both vertical and horizontal, providing an excellent dataset for geologic characterization. The
reservoir thickness is 350 ft of carbonate unit with an upper
section dominated by grainstones and packstones, and a lower
section consisting of wackestones and mudstones. Porosity and
permeability increase toward the top of the unit, where the
porosity range is between 22% and 28%. Permeability is excellent and can reach several Darcies in the so-called Super-K
layers. The permeability is enhanced by the presence of very
conductive fractures identified through different characterization tools. The area of interest is a mature area that has been
producing under peripheral waterflood for many decades.
The main objective of this study was to define the sweet
spots in this sector and to study the possibility of further
drilling opportunities in these spots. Optimization of the well’s
layout followed to ensure the optimum sweep efficiency and to
maximize recovery.
MOTIVATION
The study was motivated by the need to carefully assess the
sweep efficiency between the injection line and the central producing area. The routine monitoring and surveillance data
shows an excellent sweep in the bulk area; however, several
facts support the existence of some delimited areas with concealed potential.
This hypothesis is supported by the findings from logging
the subject reservoir in a well, Well-A, that is targeting another
deeper gas reservoir. Therefore, the dry oil column interpreted
is higher than the pre-assumed oil column. Figure 1 illustrates
the location of Well-A on a net oil column and the actual well
log.
An interesting result was obtained from the logs of another
well, Well-B; a dead well shut-in for 9 years that was presumed
to be in a swept zone based on previous surveillance results.
Subsequently, a saturation log recently indicated an oil column
of about 35 ft. Accordingly, the well was put onstream, flowing 2,000 stock tank barrels per day (stb/d), and it has been
sustaining a stable plateau for more than one year.
Fig. 1. Well-A and Well-B logs showing thicker oil column than the interpreted
data in the map.
(ROI), well spacing, fractures, water cut map, producing oil
thickness (oil bearing thickness), cumulative water flow map and
cumulative fractional flow map. Cutoff values were selected
for each attribute and were integrated to define the vertical
and areal continuity of the expected sweet spots. Obviously,
some of these attributes may represent the same value of information, so some of them were considered as primary selection
criteria and others were considered as supporting selection
criteria.
Once an area of interest was defined, it went through additional assessments that included examining the volumetric
balances and the offset well’s performance.
After encouraging results came from this assessment, the
area was classified as a sweet spot with an associated opportunity for development or for additional evaluation. Finally, the
development scenarios were assessed through numerical simulation for performance forecasting. Figure 2 gives an outline of
the adopted methodology, which will be detailed in the following paragraphs.
CHALLENGES
DATA GATHERING AND PROCESSING
The waterflood performance in the sector of interest is influenced by reservoir heterogeneity and the presence of a number
of features in the area1, 2. Aspects like fractures and Super-K
distribution are expected to have an impact on the sweep,
which increases the challenge level for efficient reservoir management3.
Additional challenges are related to the reservoir’s level of
maturity; all the wells are cutting water, and the flow profiles
recorded through the production logging tools (PLTs) show a
gradual decrease in the net oil column. As would be expected
in such a situation, surveillance measurements are focused on
the front tracking, which adds an additional difficulty to efforts
to identify the spots trapped between the fracture corridor and
preferential paths or behind the general front4.
Given the objectives and the study deliverables, different corporate databases and previous in-house studies were consulted
to collect the following data:
• Reservoir description and surveillance data, including initial well logs, production logs and reservoir saturation
logs.
• Most recent history matched full field reservoir simulation
model and the original geological model with fracture distribution — the simulation model is a dual porosity/dual
permeability model with an areal gridding of 250 m and
a very detailed vertical subdivision of 45 layers5.
• The well’s setup data, including operating status, orientation, deviation, and surface and subsurface locations.
• Reservoir pressure, production and injection data at field
and well levels.
METHODOLOGY AND WORKFLOW
To fulfill the objective of the project, which was to identify the
sweet spots, the reservoir management team has developed a
comprehensive workflow to integrate the available data, using
an organized, information value-based method, under a unified
platform. Numerous data from various sources were utilized to
conduct the study, including data from previous studies and
routine reservoir surveillance as well as from simulation models.
A substantial effort has been dedicated to collecting all these
data and capturing them in a format that is readable by the
platform being used.
A number of attributes were defined to extract the appropriate value from the different data. Some of them are basic, such
as the water saturation, and others are advanced, like the water
flow map. In total, 10 attributes were defined: net dry oil map,
isobaric map, water saturation, reservoir opportunity index
Fig. 2. Project workflow.
WINTER 2014
53
Several queries were used to extract the relevant raw data
from different sources. The raw data was then converted into a
format readable by the unified platform that was used to integrate the data.
• Water saturation model derived as a direct result from the
calibrated 3D simulation model.
• ROI computed by combining three indexes, reservoir
quality index (RQI), mobile oil saturation (Som) index
and pressure index7, in the following calculation:
ATTRIBUTES DEFINITION AND CALCULATION
This study established several reservoir engineering attributes
as major elements in the sweet spot identification workflow.
These attributes are directly or indirectly derived from water
encroachment models, fractures networks, ROI, fractional flow
calculations and numerical simulation results. The attributes
can be categorized according to the originating source, Fig. 3.
The following mapping and property calculation techniques
were used to generate these attributes:
• Isobaric map generated by the latest pressure survey data
from key wells covering the area.
• Net dry oil column generated by estimating the current
water level in each well, and subsequently the remaining
oil thickness, from production and saturation logging tools.
• Water cut map generated by mapping the trend of the
current water cut distribution in the area.
• Oil bearing column map generated by mapping the oil
producing thickness identified as the lowest oil producing
level.
• Fractures and a well spacing map generated from existing
well data, Fig. 4, and built to identify areas to be avoided,
either because they are occupied by an existing well or
because they are on a fracture pathway6.
Fig. 3. Attributes categorization.
Fig. 4. Well spacing and fractures distribution in a part of the sector.
54
WINTER 2014
where
P is reservoir pressure index
RQI is reservoir quality index:
and
SOMPV is oil saturated pore volume index:
SOMPV = SO × PV.
• Cumulative water flow map generated by computing
cumulative water flow through each grid block in the 3D
simulation model, after which the 3D model is converted
to a 2D model by summing up the cumulative water flow
for each grid vertically; this provides useful information
about the preferential water paths through the entire
history.
• Cumulative fractional flow map generated from the 3D
simulation model by computing the phase’s flow contribution for each grid block; this map is also compared to the
fractional flow calculated from the relative permeability
tables for each reservoir unit.
SELECTION CRITERIA
Once they were generated, the above mentioned attributes
were submitted to a selection process to identify reasonable
cutoffs and ranges to define any favorable spot/location for
future development.
Some attributes, such as the isobaric map, net oil column
map and oil bearing map, were used for quality checking and
providing general trends of the sweep. They were used at the
end of the project as extra filtering criteria to prioritize the selection of the sweet spots. As these maps generally show bottom-up sweep with good pressure maintenance all over the
sector and cannot be used to identify opportunities, they are
not included as the main selection criteria.
For the attributes used for the main selection process, the
cutoff value for each attribute was set as follows:
• Unfilled spaces and fractures distribution: Based on the
current spacing in the reservoir sector, a cutoff of 500 m
around each existing well and 250 m around the high
confidence fractures was used to identify space to be
avoided.
• Water saturation: A cutoff value of 50% was selected after
it was correlated and cross-checked with the two other
conjugate attributes; the water cut map and the cumulative
fractional flow map. Through the different evaluations, it
was determined that 50% water saturation will allow a
reasonable oil flow, and through this analysis, that the
water cut in such locations will not exceed 60%. Figure 5
illustrates the attributes of water saturation, cumulative
Fig. 5. Attributes of water saturation, cumulative fractional flow map and water
cut map, respectively.
fractional flow map and water cut map.
• ROI: An empirical selection of 25% as the cutoff ensuring
the best reservoir opportunity was made, corresponding
to a cutoff of 0.18, Fig. 6.
• Cumulative water flow map: A cutoff of 100,000 stb/d
was set to identify the zones where the cumulative water
flow passing through drops below that rate so the zones
can be avoided when selecting the sweet spots, Fig. 7.
Although the water saturation is included in the calculation
of ROI, it was kept as an independent attribute to provide an
additional control for the selection process, since other parameters in the ROI, such as permeability and porosity, may have
a balancing effect and dilute the water saturation effect7.
It is also important to note that a redundancy appears to exist by including both the water saturation and the water flow
map; nevertheless, each of the two parameters provides different information. The water flow map is an additive value —
summation through all layers of all water quantities passing a
particular grid block — whereas the water saturation cannot
be summed to give a holistic idea about the state of saturation
in a particular location. Water saturation can only be averaged
and this will flatten any resultant map.
attribute in Fig. 8 and defined as an area of interest (AOI). The
various attribute’s AOIs were then integrated into one map to
generate a master combined AOI covering the reservoir sector.
This AOI presents a certain areal and vertical discontinuity,
in that some areas are of infinitesimal size and so do not justify
classification as a realistic opportunity. A numerical cleaning
therefore was conducted to discard these zones. A total of 10 ft
of continuous vertical hydrocarbon thickness and 0.25 km2 of
areal connected volumes (4 grid blocks) were used as lower
limits for an area to be retained as an opportunity, Fig. 9. As a
DEFINING AREA OF INTEREST
The previously mentioned criteria and cutoffs were applied across
the study area to yield the green spots highlighted for each
Fig. 7. Cumulative water flow map in a part of the sector.
Fig. 6. Reservoir opportunity index distribution.
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for future development. Wells situated in a polygon at a distance of 1 km from the spot’s border were considered for this
review. Production, surveillance and well layout data were
used to build evaluation cards for each spot, summarizing the
review and the engineering verdict for the offset wells, Fig. 10.
Fig. 8. Retained AOI from each attribute after applying the cutoff in a part of the
sector.
SWEET SPOTS VOLUMETRIC EVALUATION
Once the risk associated with each spot was defined, a ranking
was made based on the assessed volumes. The remaining oil
volume contained in each polygon spot was calculated from
the simulation model prognosis. This volume was compared to
the spot’s initial oil in place (OIP) to extract the current recovery factor. Table 1 presents a summary of the 40 spots’
volumetric results; the spots are classified from the highest
remaining OIP. The current recovery factor reflects the state of
reserves depletion in each spot. Therefore, though there are no
wells in the spot’s polygon, the contained reserves may be
Fig. 9. Examples of removed areas with no practical opportunity value and the
retained spots.
result of all of these screening methods, 40 spots were finally
identified.
OFFSET WELLS REVIEW
To align the findings of the previous steps with an actual
neighboring well’s performance, further filtering was applied
to the defined 40 spots using the available well history, reservoir surveillance and production data. The spots then were
given a risk factor based on an engineering judgment of these
data and identified as high risk, low risk and acceptable risk
Fig. 10. Example of spot 15’s evaluation card.
Spot
Spot
Evaluation
Initial Volumes
(STOIP MMSTB)
Reaming Volumes
(STIOP MMSTB)
Jan 2014
Produced
Volumes
(MMSTB)
Current RF %
Remaining
Receivable
Reserves
(MMSTB)
1
15
Low Risk
xxxx
xxxx
xxxx
xxxx
xxxx
2
17
Med Risk
xxxx
xxxx
xxxx
xxxx
xxxx
3
31
Low Risk
xxxx
xxxx
xxxx
xxxx
xxxx
4
16
Low Risk
xxxx
xxxx
xxxx
13.6
xxxx
5
23
Low Risk
xxxx
xxxx
xxxx
3.9
xxxx
37
40
Med Risk
xxxx
xxxx
xxxx
xxxx
xxxx
38
35
Med Risk
xxxx
xxxx
xxxx
43.6
xxxx
39
14
Low Risk
xxxx
xxxx
xxxx
xxxx
xxxx
40
1
High Risk
xxxx
xxxx
xxxx
45
xxxx
Rank
Table 1. Summary of the volumetric evaluation of different sweet spots
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draining indirectly from the reservoir through the offset wells.
It is worth noting that the current recovery factor, remaining
oil and current saturation, though correlated, do not bring the
same information value. The oil saturation is certainly an indication of the sweep status, but it is categorized by grid blocks.
Looking for an average saturation — with all the associated
risk of losing all the singularities — will not give the same
exactitude as a recovery factor figure.
SWEET SPOTS DEVELOPMENT AND WELL PLANNING
The volumetric evaluation shown in Table 1 summarizes the
current status of the spots and presents a basis for the development planning for these areas. The logical approach is to look
to the different parameters together to decide if the spot is suitable for development through drilling new wells and sidetracking existing wells, or if it is more effective to conduct a further
evaluation of the region. It was decided to discard the high risk
spots from the current development, keeping them for further
evaluation through reservoir surveillance or monitoring. The
spots with low and medium risk were evaluated in terms of oil
currently in place, i.e., whether there was a substantial amount
of remaining oil; each spot was then evaluated in terms of recovery factor. The current recovery factor indicates if the offset
existing wells are able to drain those reserves or if additional
wells are needed to directly target those reserves. As it happens
(Table 1, example spot #14), a spot containing a huge amount
of OIP currently presents a high recovery factor. This indicates
that there is no need to add additional wells, leaving only a
sidetrack of those wells showing low performance to be considered. The process schematic is described in Fig. 11.
Drilling new horizontal laterals in the retained potential areas was chosen as the main production development method,
by either new drilling or reentry drilling from offset vertical
wells. Later surveillance recommendations based on data from
PLTs and reservoir saturation logs will be provided to better
assess the discarded areas. Each of the individual spots will
then receive a final specific recommendation with the specific
name of the well:
• New well(s) for development.
Fig. 11. Procedure for designating level of development for the sweet spots.
• Sidetrack of existing specific well.
• Conduct production logging or saturation log in the
specific well(s).
Well planning is optimized by defining the trajectory of the
horizontal section3. The lateral is typically placed in the best
layer in the top of the reservoir, Fig. 12.
SIMULATION PREDICTION AND FINAL WELL LAYOUT
A total of 32 laterals were designed and nine new wells and 23
reentries from existing inactive or marginal producers are illustrated in Fig. 13. The reservoir contacts of these wells were
optimized, with placement between 1,000 ft and 5,000 ft near
the reservoir top, considering the current well’s spacing.
To better capitalize on the designed wells, the proposed
well’s production performances, production targets plateau
and cumulative produced volumes were assessed through simulation prediction. The prediction confirmed the added value
Fig. 12. Example of well sidetrack design.
WINTER 2014
57
Fig. 13. Final proposed well development layout in a part of the sector.
of the majority of the wells (28 out of 32) and provided a basis
to include these wells in the field business plan for the upcoming years. Figure 14 illustrates the proposed development of
spot #23 as an example.
CONCLUSIONS
This study presents a comprehensive workflow with clear logical processes to seize the advantage of available reservoir data
to identify future developments in a mature area of a giant
field. The data is integrated through an information valuebased method that provides relevant attributes with which to
conduct the study. In this study, 10 attributes were calculated
to describe reservoir characteristics in terms of saturation,
reservoir quality, fluid flows, and production and surveillance
data. Cutoffs are applied to the defined attributes through a
well-established selection process to delineate the areas of
interest. Areas compliant with the selection criteria are then
Fig. 14. Spot 23 development example.
58
WINTER 2014
submitted to additional evaluations, which integrate the offset
well’s performance and surveillance data to further distinguish
the sweet spots. After a study concludes that development opportunities are not limited to in-fill drilling in the mature crestal
area, but that potential spots also exist elsewhere, risk profiles
are assigned to each spot based on volumetrics and the ability
of the offset well to drain the reserves in the spot. A risk and
reward evaluation finally leads to the design of the best scenario for developing these spots or to the need for additional
evaluation requirements. These recommendations will serve to
feed the field development plan for the upcoming years.
ACKNOWLEDGMENTS
Aramco for their support and permission to publish this article. The authors also want to acknowledge the contributions of
Soha Hayek, Lajos Benedek, Sikandar Gilani and Saad Mutairi
for reviewing the article and Nayif Jama for assisting with the
required simulation runs.
REFERENCES
1. Alhuthali, A.H., Al-Awami, H.H., Soremi, A. and AlTowailib, A.I.: “Water Management in North ‘Ain Dar,
Saudi Arabia,” SPE paper 93439, presented at the SPE
Middle East Oil and Gas Show and Conference, Bahrain,
March 12-15, 2005.
2. Alhuthali, A.H.: “Optimal Waterflood Management under
Geologic Uncertainty Using Rate Control: Theory and
Field Applications,” SPE paper 129511, presented at the
SPE Annual Technical Conference and Exhibition, New
Orleans, Louisiana, October 4-7, 2009.
3. Yuen, B.B.W., Rashid, O.M., Al-Shammari, M., Al-Ajmi,
F.A., Pham, T.R., Rabah, M., et al.: “Optimizing
Development Well Placements within Geological
Uncertainty Utilizing Sector Models,” SPE paper 148017,
presented at the SPE Reservoir Characterization and
Simulation Conference and Exhibition, Abu Dhabi, UAE,
October 9-11, 2011.
4. Pham, T.R., Al-Otaibi, U.F., Al-Ali, Z.A., Lawrence, P. and
van Lingen, P.: “Logistic Approach in Using an Array of
Reservoir Simulation and Probabilistic Models in
Developing a Giant Oil Reservoir with Super-Permeability
and Natural Fractures,” SPE paper 77566, presented at the
SPE Annual Technical Conference and Exhibition, San
Antonio, Texas, September 29 - October 2, 2002.
5. Alzankawi, O.M., Al-Houti, R.A., Ma, E., Ali, F.A.,
Alessandroni, M. and Alvis, M.: “Mauddud Fractured
Reservoir Analysis, Greater Burgan Field: Integrated
Fracture Characterization Using Static and Dynamic Data,”
IPTC paper 17471, presented at the International
Petroleum Technology Conference, Doha, Qatar, January
19-22, 2014.
6. Abd-Karim, M.G. and Abd-Raub, M.R.B.: “Optimizing
Development Strategy and Maximizing Field Economic
Recovery through Simulation Opportunity Index,” SPE
paper 148103, presented at the SPE Reservoir
Characterization and Simulation Conference and
Exhibition, Abu Dhabi, UAE, October 9-11, 2011.
7. Stabell, F.B., Stabell, C.B. and Martinelli, G.: “Effective
Assessment of Resource Plays: Handling Transition
Zones,” SPE paper 167724, presented at the SPE/EAGE
European Unconventional Resources Conference and
Exhibition, Vienna, Austria, February 25-27, 2014.
WINTER 2014
59
BIOGRAPHIES
Dr. Ahmed H. Alhuthali is a Division
Head in Saudi Aramco’s Southern Area
Reservoir Management Department,
overseeing the reservoir engineering
and operational issues of the
‘Uthmaniyah area — the largest in the
giant Ghawar field. Prior to this
assignment,
i
t he
h held
h ld reservoir management and production
engineering positions in different areas of Ghawar and
Abqaiq fields. Ahmed has been with Saudi Aramco for 16
years.
He is interested in integrated reservoir management with
an emphasis on waterflooding principles, closed loop
optimization, well performance and probabilistic decision
analysis. Ahmed is also interested in energy economics,
especially in the oil and gas sector.
He received his B.S. degree in Electrical Engineering
from King Fahd University of Petroleum and Minerals
(KFUPM), Dhahran, Saudi Arabia, in 1998 and an M.S.
degree in Petroleum Engineering from Texas A&M
University, College Station, TX, in 2003. Ahmed received
his Ph.D. degree in Petroleum Engineering from Texas
A&M University, College Station, TX. He also earned a
business certificate from Mays Business School at Texas
A&M University in May 2008.
Abdullah I. Al-Sada joined Saudi
Aramco in 2012 as a Reservoir
Engineer working in the Southern Area
Reservoir Management Department.
He is currently working in the
‘Udhailiyah Reservoir Management
Division involved in the reservoir
engineering and operational
issues of the ‘Uthmaniyah area
oper
— the largest in the giant Ghawar field. Abdullah’s
interests include the reservoir management of mature fields
and maximizing the efficiency of secondary recovery
methods with respect to the asset’s heterogeneity.
In 2012, he received his B.Eng. degree in Petroleum
Engineering from King Fahd University of Petroleum and
Minerals (KFUPM), Dhahran, Saudi Arabia.
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WINTER 2014
Mohamed T. Bouaouaja joined Saudi
Aramco in March 2013 as a Petroleum
Engineer working in the Southern Area
He started his career in Tunisia where
he worked for the national oil
company ETAP as a Reservoir
Engineer,
involved
E
i
i
l d in
i reservoir management for both
carbonate and clastic reservoirs. In 2007, Mohamed joined
Schlumberger and worked in various assignments in
consultancy, simulation, training and project management
with an international exposure and a focus on the Arabian
Gulf countries.
He has published several technical reports, studies and
Society of Petroleum Engineer (SPE) papers.
In 2001, Mohamed received his B.S. degree in Civil
Engineering Hydraulics from Ecole Nationale d’ingenieurs
de Tunis (ENIT), Tunis, Tunisia.
Abdullah A. Al-Safi joined Saudi
Aramco in 1986 as a Petroleum
Engineer. During his career, he has
worked in several different production
fields and in various jobs, including as
a Drilling Engineer and a Production
Engineer. Abdullah currently works as
a Petroleum Engineer
Enginee Specialist in the Southern Area
He has coauthored several Society of Petroleum
Engineers (SPE) papers.
In 1986, Abdullah received his B.S. degree in Petroleum
Engineering from King Saud University, Riyadh, Saudi
Arabia.
Innovation in Approach and Downhole
Equipment Design Presents New
Capabilities for Multistage Stimulation
Technology
Authors: Mohammed A. Al-Ghazal, Saad M. Al-Driweesh, Mustafa R. Al-Zaid and Fadel A. Al-Ghurairi
ABSTRACT
To date, multistage stimulation (MSS) technologies have been
run in almost every type of complex hydrocarbon-bearing rock,
from the much heralded shale plays in North America to the
massive heterogeneous carbonate formations exhibiting a dual
porosity/dual permeability system in Saudi Arabia. These technologies have also been used in offshore wells in the North
Sea, Black Sea and West Africa.
The main MSS market was and still is in North America, in
the tight unconventional shale plays; however, in recent years,
the international market (outside of North America) has been
steadily catching up. One of the main leaders associated with this
increase has been Saudi Aramco in its Southern Area gas fields.
MSS has often been viewed as simply running a completion
string followed by pumping services; however, the early attempts
at uncemented open hole MSS completions in Saudi Arabia
were met with mixed operational success. It became clear that
the standard completion approach and stimulation procedures
could not be directly applied there. A new set of best practices
would be required in these Middle East wells, one that included
an integrated multidisciplinary approach that took a step backwards in the process — to the pre-drilling phase — and focused
on well planning optimization to maximize the multistage
completion technique and ultimately the well productivity.
The wide range of reservoir types required engineering of the
MSS completion to enable placement of a variety of matrix and
fracturing stimulation techniques, further complicated by the
constraints associated with operating in environments ranging
from land and/or the desert to offshore areas. These completion
options have included low-tier sand plugs, more sophisticated
bridge and frac plugs, and high-end, open hole, uncemented
liners with packers and sleeves. For Middle East wells, it is
clear that “one MSS completion technique does not fit all.”
This article will discuss many of these MSS solutions and
highlight some of the debate over the merits of the various
MSS completion designs and options — such as the preferences in isolation methods and options for connecting the wellbore to the reservoir — as deployed in the Southern Area tight
gas fields of Saudi Arabia. Regardless of which MSS technology
is applied, further emphasis is being placed on the integration
of the completion and the stimulation treatment from the initial
design of the well, to optimize reservoir contact and maximize
the return on investment.
Testing and field applications of newly proposed, developed
and implemented MSS solutions are also presented, including
an innovative packer seal technique, an engineered approach
for optimal performance of fracturing sleeves, nonstandard
ball increment spacing sizes, curved ball seats and a segmented
body for full bore mill-out.
INTRODUCTION
For over a decade, multistage stimulation (MSS) has been a
well-established technique in North America and is also in a
period of rapid growth in many regions in the Middle East.
Globally, operators have applied a multitude of MSS completion options to wells in many varying reservoirs, from conventional reservoirs, to tight gas/tight oil basins, to carbonate and
clastic formations, to more unconventional shale and coalbed
methane reservoirs1-12.
A huge amount of information, best practices and techniques has been leveraged from the North American MSS
experiences; however, as experience within the Middle East
environment developed, differences among the MSS techniques
and processes became clear. Certainly as a starting point, the
differences logistically between the North American market
and the international market are immediately evident; where
tens of stages (30, 40, 50 stages and more) are deployed and
fracture stimulated over the space of days in North America,
stimulating the same number of stages would take weeks in
many international locations. Therefore, the international
stage count is significantly less and typically in open hole uncemented applications. For example, outside of North America,
a maximum of 10 stages can be deployed, with an average of 4
to 5 stages, in a single lateral well. For that reason, a great deal
of focus is placed on efficiency in North America, where internationally, and in the Middle East in particular, the majority of
the focus is on effectiveness. For example, in Saudi Arabia, if
five stages are deployed, a full five stages should be fracture
stimulated to the fullest to be seen as contributing individually
to their maximum potential.
With that said, judging from the previously installed open
hole, uncemented, lower completion systems (of which there
WINTER 2014
61
are approximately 80 in total) in the Saudi Arabia area, the
equation of “number of stages deployed” being equal to
“number of stages stimulated” is yet to be satisfactorily realized. One of the main issues is related to the difference
between utilizing open hole MSS systems in a carbonate formation, where acid fracturing treatments are applied, and
utilizing them in a shale formation, where proppant fracturing
takes place. The concerns when using a MSS system in an acid
fracturing environment are the zonal isolation between stages
and ultimately the packer isolation technique selected.
A typical hydraulic-set mechanical packer uses one or two
seal elements that are approximately 8” to 10” in length while
being deployed, and then when the packer is hydraulically set,
a piston force is applied to the solid rubber element, which is
forced outwards, expanding in outside diameter while contracting in overall length. That means the more the packer’s
outside diameter expands, the less the contact seal length
pressed to the open hole formation face becomes.
This of course is assuming a perfect “gun barrel” open hole
circumference where a mechanical packer can be set uniformly
to the formation face. The worst case scenario is when ovality
from washouts and breakouts is present. The mechanical
packer attempts to conform to the open hole circumference;
however, on occasions where ovality is present, the potential
exists for a micro-annulus space to occur between the packer
seal and the formation face, Figs. 1 and 2. Now, in standard
shale/sandstone MSS applications, where proppant rather than
acid is pumped, this micro-annulus leak path can easily pack
off with proppant in what becomes a self-healing process, and
the isolation between stages is restored, Figs. 3 and 4. Given
the nature of the acid fracturing treatment in a carbonate formation, however, this leak process is not self-healing, and the
phenomenon of acid working its way through the micro-annulus and dissolving away the rock around the packer seal can be
very problematic.
There is a clear need therefore, for an optimized packer
seal technique in MSS acid fracturing applications in carbonate
formations.
Figs. 1 and 2. An acid fracturing case in a carbonate formation showing a slight
washout at the upper side of the lateral where the acid dissolving away some of
the formation around the seal causes communication between stages.
Figs. 3 and 4. A proppant fracturing case in a shale/sandstone application showing
a slight washout at the upper side of the lateral where packing off around the seal
ensures zonal isolation is achieved.
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PROPOSED MSS SOLUTION
Development and qualification of a fit-for-purpose multistage
swellable element was required for use in the environment of
the southern gas fields in Saudi Arabia, a packer that could
withstand harsh conditions in terms of bottom-hole temperatures and pressures as well as the acid fracturing application
needed by the carbonate formations, Figs. 5 and 6.
Previous attempts had been made to use more conventional
standard swellable packers, adapted from water shutoff or inflow control device type applications. The challenge was always
fulfilling the differential pressure requirements of the fracturing
treatment, and the conventional method was to use standard
application rubber materials and simply increase the length of
the swellable elastomer. This resulted in the adoption of packer
lengths of 32 ft or more to meet the high differential pressure
requirements of the multistage treatments. The positive outcome
was a longer seal length, and therefore, a reduced possibility of
the acid dissolving the rock formation around the seal — as
highlighted earlier, that is a major concern for the acid fracturing application. The negative outcome, on the other hand, was
always the impact of the longer seal length of the swellable
packer on deployment during the installation process. For example, with several long swellable packers being deployed in a
single lower completion string, reaching target depth became a
significant concern. A great deal of time and effort will be spent
in determining the optimum stage lengths and open hole packer
positions prior to running the MSS equipment, but when the
lower completion becomes mechanically stuck and ultimately
set off depth, all this effort becomes wasted and the production
results are ultimately never fulfilled.
The challenge of deploying MSS systems to target depth is
not new in Saudi Arabia, and even with hydraulic-set mechanical packers, the initial MSS systems saw installations prematurely set several hundred feet off depth. The preferred
configuration for running the MSS system involved having
every fracturing sleeve placed between two open hole packers,
resulting in what is known as a “balanced system,”13 where
the fracturing forces are balanced between pressurized stages.
The consequence of having a balanced system installation set
prematurely was that the toe of the well was isolated by the
lowermost open hole packer and therefore was unable to be
stimulated. From that point, an open hole anchor packer
would be run in an “unbalanced” multistage configuration,
meaning the first toe stage was unbalanced by having a fracturing port placed below the lowermost open hole packer.
Therefore, if the MSS completion system was set prematurely
Figs. 5 and 6. The newly designed swellable element must achieve positive
isolation in carbonate formations with acid fracturing applications (left image), as
well as in sandstone/shale proppant fracturing cases (right image).
off depth, then there was still the possibility of stimulating the
toe section of the well, albeit if it was a very long section. The
upward forces placed on the bottom of the lowermost packer,
however, would be very large, as per the term unbalanced, and
sliding of that packer would be likely. So the idea of deploying
an open hole anchor packer became of interest, with the intent
of anchoring the bottom of the completion string and resisting
the movement caused by the large upward piston forces placed
on that lower open hole packer.
This unbalanced configuration worked well in shale type
applications. Consequently, in carbonate formations, on occasion during the acid fracturing treatments of the first stage, as
solution was pumped through the hydraulic frac sleeve, significant and instantaneous pressure drops were noted, and it was
believed that the acid treatment had dissolved away the carbonate rock around the slips, and therefore the anchor had
released, creating an immediate upward movement of the
lowermost open hole packer.
Once the deployment issues were rectified and completions
no longer became stuck14, 15, the standard practice of running
balanced configurations resumed and the open hole anchor
packer become redundant. The proposed open hole solutions
that followed did not require open hole anchor packers in the
lower completion string.
A second challenge was related to the fracturing port configuration. On occasion the integrity of the ball and ball seat interface came into question. For example, during treatments
where instantaneous pressure drops of several thousand psi or
more were seen in the middle of the acid fracturing process —
typically this was interpreted as a mechanical failure — the
cause was loss of integrity between the ball and ball seat interface. Therefore, a more robust fracturing sleeve that incorporated a newly designed ball seat was tested and qualified.
Yet a coiled tubing (CT) mill-out of the ball seats in the
multistage completions can be required in some cases16, 17. The
results of previous CT mill-outs have been widely varied, and
even if the practice of CT milling has been significantly improved in terms of bottom-hole assemblies (BHAs), mills and
motors, as well as milling procedures, failures still occur.
Therefore, the new, more robust ball seat was also required —
from the opposite side — to be easily millable.
NEWLY DEVELOPED AND FIT-FOR-PURPOSE
SWELLABLE PACKERS FOR MULTISTAGE ACID
FRACTURING APPLICATIONS
The development that followed resulted in a multistage
swellable packer (MSwP) isolation system designed to achieve
open hole and cased hole isolation in many varied applications, from well construction to well completion. The swellable
element is specially designed for the typically higher pressure
ratings associated with a multistage fracturing job, Fig. 7.
The swellable packer is engineered from a complex polymer
that has properties similar to those of rubber before swelling.
Fig. 7. Newly developed fit-for-purpose swell packer for multistage fracturing
applications.
The mechanism of the oil swell technology is to use the thermodynamic diffusion of hydrocarbons into the polymer network to cause stretching and volumetric expansion of the
packer. The MSwP system, which employs bonded-to-pipe
swellable packers, integrates a patented, double brass fold
back shoe design to act as an anti-extrusion device, ensuring
better pressure and temperature ratings and reliability. The
MSwP assembly also has a built-in swelling delay mechanism
that allows thermodynamic absorption to start immediately after installation. This delay, achieved without any external coatings, reduces premature swelling risks while the assembly is
being run in the hole. Because of the MSwP assembly’s advanced polymer construction and its anti-extrusion device design, its differential pressure capabilities are suitable for high
fracturing pressures — an indispensable criterion for a fracturing packer if isolation is required.
MSWP BONDED-TO-PIPE SWELLABLE PACKERS WITH
FOLD BACK SHOE TECHNOLOGY
Multistage operators have expressed concern that swellable
packers may not reliably seal open hole completions. To investigate this concern, benchmark testing was undertaken. The
test results support the idea that industry pressure ratings may
be marginal. For example, the industry length for 6,000 psi
service is around 6 ft, and although it is possible to approach
this pressure with conventional designs, overall performance
has been suspect.
A root cause analysis identified the annular extrusion gap as
a limiting factor in pressure capability. The industry method to
compensate is to increase the element length. While helpful,
this adds cost and fails to address the root cause of the weakness. To remedy the problem, a patented, cost-effective fold
back shoe technology was designed. The fold back shoes are
fixed to the ends of the element. Swelling and axial pressures
deploy the shoes to cover the annular extrusion gap. This feature yields industry-leading pressure performance and reliability. Figures 8 and 9 illustrate the fold back shoe technology.
Several pressure tests were conducted and the test results
show a linear dependence between the length of the element
and the pressure rating, which will be higher for smaller open
hole sizes due to less swelling. The bonded-to-pipe oil swellable packers, because of their robust rubber material coupled
with the fold back shoe design, are capable of performing in
the ranges of 1,600 psi/ft to 3,300 psi/ft, Fig. 10.
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Nonstandard Ball Increment Spacing Sizes
Fig. 8. Pre-test swell packer with fold back shoes on both ends.
Fig. 9. Post-test swell packer with fold back shoes deployed.
Fig. 10. The graph is validated by actual full scale testing in various hole sizes.
ENGINEERED APPROACH FOR OPTIMAL
PERFORMANCE OF FRACTURING SLEEVES
Together with the new open hole isolation packer, the development of a sliding sleeve with an incorporated ball seat design
has been the main contributor to the successful application of
the MSS technology. The use of incrementally increasing ball
diameters — moving from toe to heel — has resulted in the
possibility of deploying a high number of stages. Initially, the
increment sizes typically started at ¼”, and as the demand for
more stages increased, the simplest method to meet this demand was to reduce the ball increment size to ⅛”. Not satisfied with this either, the operators in North America pushed
for further increases in stage count and some suppliers started
deploying systems with 1/16” ball increment sizes. At issue was
that the operational needs were outpacing the engineering
required to fully test and qualify these modifications.
A step backwards was required to properly model and test
what suppliers had been proposing. It was clear that when the
increment size and the overlap area between the ball and the
ball seat fell below a certain value, there was a tendency for
the ball to fail or become wedged in the ball seat, thereby preventing flow back of the ball. This phenomenon was made
worse by larger balls; the larger the ball, the higher the risk of
the ball becoming wedged in its seat. Taking an engineered approach to the ball and ball seat interface quickly determined
that the larger balls needed a larger clearance between the ball
and ball seat. Simply stated, a thicker metal was needed to be
able to withstand the wedging effect; therefore the increment
size had to be higher than the ⅛” range. For the smaller sized
balls, the increment size could be reduced, and the spacing between the ball sizes could be decreased to less than ⅛” increment sizes. The ultimate achievement was to adopt nonstandard increments for the full range of ball sizes, so as to
create equal forces between the ball and the ball seat’s interface
for all sizes, Fig. 11.
Curved Ball Seats
Additionally, with this ball and ball seat interface in mind, several studies were performed to analyze the stresses acting on
the ball after it contacted the ball seat area. With a conventional ball seat, the standard shape on the contact angle is a
30° profile. Testing and actual operations showed that this typically created a sharp stress point that either resulted in the ball
cracking during the fracturing treatment or the ball becoming
wedged in the ball seat itself, Fig. 12. The optimum design was
found to be a “curved” ball seat, which resulted in a uniform
stress distribution across the ball and seat interface, Fig. 13.
Segmented Body for Full Bore Mill-out
CT mill-out of the ball seats has always been a problematic
area, prompting discussion16, 17. Even with the optimum
Fig. 11. Ball seat increment calculations and finite element analysis for ball interface optimization.
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Fig. 12. Conventional ball seat’s high stress points potentially cause cracking or “egging” of the ball.
MSWP COMPLETION SYSTEM OPERATIONAL
EXECUTION
Fig. 13. Curved ball seat design — uniformly distributed stresses across the ball
seat reduce the chance of failure.
milling BHA and procedures, failures still occur. In addition to
optimizing the ball seat with a very robust design for the fracturing operation, it was noted straightaway that the ball seat
design should also be easy to mill.
The new ball seat has a segmented design that allows for
smooth and simple milling operation. Another notable feature
is that the ball seat can be milled out full bore, compared to
the conventional design, which leaves a slither of metal after
mill-out that can easily cause further problems with the CT
operation and increases the risk of sticking or damaging the
CT pipe, Fig. 14.
Well-X was drilled and the pilot hole encountered good porosity development in reservoir-B, layer B1, with 40 ft true vertical depth net pay and 10% average porosity. Further analysis
showed good reservoir quality but limited drainage volume.
The existing vertical well was then sidetracked in the minimum
stress direction with a horizontal lateral to maximize the reservoir contact, and it was equipped with a three-stage MSS completion to enhance the well productivity. The open hole MSS
technology to be trial tested on this well was a 4½” MSS system with swellable packers.
A 5⅞” open hole section of 2,831 ft was drilled without issue to 15,443 ft measured depth. An open hole reamer trip
was run prior to running with a 4½” MSS, and one tight spot
was encountered at 12,950 ft to 13,000 ft. The assembly was
washed and reamed without rotation. The 4½” MSS assembly,
including a liner hanger system, was smoothly deployed to total
depth. A 1.700” ball was dropped to flow through the circulation valve and the valve was closed at 1,200 psi. With a closed
system in place, the liner hanger was set at 2,000 psi and the
running tool was released at 3,000 psi. The running tool was
picked up and the liner top packer was set with 80,000 pounds
(klb) of slack off. The liner top packer was tested from the
annulus side to 3,000 psi for 15 minutes, Fig. 15.
Fig. 14. Improved millable design, compared to the conventional design, of the ball seat.
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Fig. 15. Geolograph showing sequence of events.
The upper completion string with a tieback seal assembly
was landed in the tubing receptacle. The tubing pressure was
increased to 8,800 psi. A clear indication was seen that the hydraulic frac valve had opened, Fig. 16.
The newly opened, unstimulated, internal toe was expected to
be very tight, and that proved to be the case as, at a relatively
low circulation rate of 5 barrels per minute (BPM), a maximum bottom-hole pressure (BHP) of 15,000 psi was reached.
Regardless of the lack of injectivity, the instantaneous shut-in
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pressure was 600 psi lower than the first injection test, meaning that the formation had released pressure due to the previous flow back. The fact that the formation was able to release
pressure from previous flow back shows that all previously injected volume had been taken by the reservoir; poroelasticity
therefore was having a significant effect in the near wellbore
area, limiting injection rate and volume. A decision was then
made to spot acid with CT to improve injectivity. Consequently, a total of 100 bbl of 20% hydrochloric (HCl) acid
inject into the formation, a decision was made to perform an
acid squeeze with CT. After injection with CT at a rate of 6.5
BPM, a decision was made to perform an injection test with
the fracturing equipment. The injection test showed pressure
stability at the pumping rate of 20 BPM, which allowed the
possibility of performing an acid fracturing treatment, Fig. 17.
Subsequently, 1,900 bbl of treatment fluid, including diverting
agent, 28% HCl acid and treated water were pumped.
Overall, the acid injectivity in Stage 2 was very good, typically between 20 BPM and 30 BPM. Stage 1 showed poor injectivity with 1 BPM to a maximum of 8 BPM (for a very short
period). This is a clear case of compartmentalization being exhibited by the swellable packers. If there had been channeling
past the swellable packers, both zones should have exhibited
similar injectivity behavior.
CONCLUSIONS
The following conclusions were noted from the performance of
the new multistage fracturing completion equipment:
Fig. 16. Pressure increased to 8,800 psi and dropped to 7,450 psi before holding
steady. This gave a clear indication that valve had opened.
was pumped and over displaced with 70 bbl of treated water.
During the displacement, the pressure increased from 5,500 psi
to 6,200 psi.
Following the end of the first stage, the decision was to proceed with the second stage. A 3” magnesium ball was allowed
to free fall in the vertical section for an hour. After an hour,
pumps were started at a constant rate of 3 BPM. A clear indication was seen of the ball landing on the seat; the pressure
increased from 4,100 psi to 6,100 psi, and then an immediate
fall in pressure to 5,200 psi was seen, indicating that the sleeve
had been opened and a new zone was available.
Due to the positive opening of the sleeve and the ability to
• An integrated approach, involving all departments from the
operator side as well as positive communication with the
service company, assisted in making the overall operation a
complete success.
• Thorough full-scale swellable packer testing demonstrated
that the equipment exceeded the operational pressure and
temperature considerations as well as the acid treatment
type.
• No operational lost time was recorded during the
completion deployment operation as well as during the
stimulation treatment.
• The newly developed and installed swellable packers were
successfully able to withstand and compartmentalize the
fracturing pressure exerted.
• The hydraulic frac sleeve was successfully opened at the
first attempt, and a positive indication was recorded. An
Fig. 17. Injectivity test for the newly opened Stage 2.
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67
injectivity test showed a very tight formation across the toe
section.
• A successful opening of the ball actuated frac sleeve was
observed; this was proven by a clear pressure response
when the ball landed onto the ball seat and the sleeve
opened to the new formation zone.
• The high fracture injection pressure response proved that a
new zone was initiated, verified by BHP evaluation during
the DataFRAC and main acid fracturing treatment.
• The multistage completion equipment was successfully
deployed to the target depth as per all the well objectives.
ACKNOWLEDGMENTS
Aramco for their support and permission to publish this article. Also, the authors would like to recognize Saudi Aramco
and the service company employees who are involved in multistage fracturing in Saudi Arabia.
This article was presented at the International Petroleum
Technology Conference, Kuala Lumpur, Malaysia, December
10-12, 2014.
REFERENCES
1. Schmelzl, E., Schlosser, D., Alvarez, D. and Gulewicz, D.:
“CTU Deployed Frac Sleeves Benchmark Horizontal
Multistage Frac Isolation Performance,” SPE paper
169574, presented at the SPE Western North America and
Rocky Mountain Joint Regional Meeting, Denver,
Colorado, April 16-18, 2014.
2. Yalavarthi, R., Jayakumar, R., Nyaaba, C. and Rai, R.:
“Impact of Completion Design on Unconventional
Horizontal Well Performance,” SPE paper 168673,
presented at the Unconventional Resources Technology
Conference, Denver, Colorado, August 12-14, 2013.
3. Ingram, S.R., Lahman, M. and Persac, S.: “Methods
Improve Stimulation Efficiency of Perforation Clusters in
Completions,” Journal of Petroleum Technology, April
2014, pp. 31-36.
4. King, G.E.: “Best Practices Lead to Successful Shale
Fracturing,” World Oil, Vol. 235, No. 3, March 2014, pp.
79-83.
5. Yuan, F., Blanton, E., Convey, B.A. and Palmer, C.:
“Unlimited Multistage Completion System: A BallActivated System with Single Size Balls,” SPE paper
166303, presented at the SPE Annual Technical Conference
and Exhibition, New Orleans, Louisiana, September 30 October 2, 2013.
6. Al-Ghazal, M.A., Al-Driweesh, S.M., Al-Ghurairi, F.A., AlSagr, A.M. and Al-Zaid, M.R.: “Assessment of Multistage
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Fracturing Technologies as Deployed in the Tight Gas
Fields of Saudi Arabia,” IPTC paper 16440, presented at
the International Petroleum Technology Conference,
Beijing, China, March 26-28, 2013.
7. Al-Ghazal, M.A., Al-Ghurairi, F.A. and Al-Zaid, M.R.:
“Overview of Open Hole Multistage Fracturing in the
Southern Area Gas Fields: Application and Outcomes,”
Saudi Aramco Ghawar Gas Production Engineering
Division Internal Documentation, March 2013.
8. Al-Ghazal, M.A. and Abel, J.T.: “Stimulation Technologies
in the Southern Area Gas Fields: A Step Forward in
Production Enhancement,” Saudi Aramco Gas Production
Engineering Division Internal Documentation, October
2012.
9. Al-Ghazal, M.A., Al-Sagr, A.M. and Al-Driweesh, S.M.:
“Evaluation of Multistage Fracturing Completion
Technologies as Deployed in the Southern Area Gas Fields
of Saudi Arabia,” Saudi Aramco Journal of Technology,
Fall 2011, pp. 34-41.
10. Al-Ghazal, M.A., Al-Driweesh, S.M. and El-Mofty, W.:
“Practical Aspects of Multistage Fracturing from
Geosciences and Drilling to Production: Challenges,
Solutions and Performance,” SPE paper 164374,
presented at the SPE Middle East Oil and Gas Show and
Exhibition, Manama, Bahrain, March 10-13, 2013.
11. Rahim, Z., Al-Anazi, H.A. and Al-Kanaan, A.A.:
“Improved Gas Recovery – 1: Maximizing Post-Frac Gas
Flow Rates from Conventional, Tight Gas,” Oil and Gas
Journal, March 2012, pp. 76.
12. Rafie, M., Said, R., Al-Hajri, M., Al-Mubarak, T., AlThiyabi, A., Nugraha, I., et al.: “The First Successful
Multistage Acid Frac of an Oil Producer in Saudi
Arabia,” SPE paper 172224, presented at the SPE Saudi
Arabia Section Annual Technical Symposium and
Exhibition, al-Khobar, Saudi Arabia, April 21-24, 2014.
13. Rahim, Z., Al-Kanaan, A.A., Johnston, B., Wilson, S., AlAnazi, H.A. and Kalnin, D.: “Success Criteria for
Multistage Fracturing of Tight Gas in Saudi Arabia,” SPE
paper 149064, presented at the SPE/DGS SAS Technical
Symposium and Exhibition, al-Khobar, Saudi Arabia,
May 15-18, 2011.
14. Wilson, S. and Johnston, B.: “Successful Deployment of
Multistage Fracturing Systems in Multilayered Tight Gas
Carbonate Formations in Saudi Arabia,” SPE paper
130894, presented at the SPE Deep Gas Conference and
Exhibition, Manama, Bahrain, January 24-26, 2010.
15. Al-Ghazal, M.A., Al-Driweesh, S.M. and Al-Ghurairi,
F.A.: “Upgrading Multistage Fracturing Strategies Drives
Double Success after Success in the Unusual Saudi Gas
Reserves,” SPE paper 168071, presented at the SPE Saudi
Arabia Section Annual Technical Symposium and
Exhibition, al-Khobar, Saudi Arabia, May 19-22, 2013.
16. Al-Ghazal, M.A., Abel, J.T., Wilson, S., Wortmann, H.
and Johnston, B.B.: “Coiled Tubing Operational
Guidelines in Conjunction with Multistage Fracturing
Completions in the Tight Gas Fields of Saudi Arabia,”
SPE paper 153235, presented at the Middle East
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17. Al-Ghazal, M.A., Abel, J.T., Al-Buali, M.H., AlRuwaished, A., Al-Sagr, A.M., Al-Driweesh, S.M., et al.:
“Coiled Tubing Best Practices in Conjunction with
Multistage Completions in the Tight Gas Fields of Saudi
Arabia,” SPE paper 160833, presented at the SPE Saudi
Arabia Section Technical Symposium and Exhibition, alKhobar, Saudi Arabia, April 8-11, 2012.
BIOGRAPHIES
Mohammed A. Al-Ghazal is a
Production Engineer at Saudi Aramco.
He is part of a team that is responsible
for gas production optimization in the
Southern Area gas reserves of Saudi
Arabia. During Mohammed’s career
with Saudi Aramco, he has led and
participated in several
severa upstream projects, including those
addressing pressure control valve optimization, cathodic
protection system performance, venturi meter calibration,
new stimulation technologies, innovative wireline
technology applications, upgrading of fracturing strategies,
petroleum computer-based applications enhancement and
safety management processes development.
In 2011, Mohammed assumed the position of Gas
Production HSE Advisor in addition to his production
engineering duties.
In early 2012, Mohammed went on assignment with the
Southern Area Well Completion Operations Department,
where he worked as a foreman leading a well completion
site in several remote areas.
As a Production Engineer, Mohammed played a critical
role in the first successful application of several high-end
technologies in the Kingdom’s gas reservoirs.
In 2010, Mohammed received his B.S. degree with
honors in Petroleum Engineering from King Fahd
University of Petroleum and Minerals (KFUPM), Dhahran,
Saudi Arabia.
He has also authored and coauthored several Society of
Petroleum Engineers (SPE) papers and technical journal
articles as well as numerous in-house technical reports.
Additionally, Mohammed served as a member of the
industry and student advisory board in the Petroleum
Engineering Department of KFUPM from 2009 to 2011.
As an active SPE member, he serves on the Production
and Operations Award Committee.
Recently, he won the best presentation award at the
production engineering session of the 2013 SPE Young
Professional Technical Symposium.
Mohammed is currently pursuing an M.S. degree in
Engineering at the University of Southern California, Los
Angeles, CA.
Saad M. Al-Driweesh is a General
Supervisor in the Southern Area
Production Engineering Department,
where he is involved in gas production
engineering, well completion, and
fracturing and stimulation activities.
Saad is an active member of the
SSociety
i t off Petroleum Engineers (SPE), where he has chaired
several technical sessions in local, regional and
international conferences. He is also the 2013 recipient of
the SPE Production and Operations Award for the Middle
East, North Africa and India region. In addition, Saad
chaired the first Unconventional Gas Technical Event and
Exhibition in Saudi Arabia.
He has published several technical articles addressing
innovations in science and technology. Saad’s main interest
is in the field of production engineering, including
production optimization, fracturing and stimulation, and
new well completion applications. He has 26 years of
experience in areas related to gas and oil production
engineering.
In 1988, he received his B.S. degree in Petroleum
Mustafa R. Al-Zaid is a Gas
Production Engineer with Saudi
Aramco’s Southern Area Production
Engineering Department. He is part of
a gas production optimization team,
which is responsible for well
completion, stimulation and fracturing
activities in the Ghawar
Ghaw field.
Mustafa has designed and executed several critical
rigless well interventions, including wireline operations and
coiled tubing stimulation and cleaning in the Ghawar field.
Engineering from the University of Adelaide, Adelaide,
Australia. Mustafa has also successfully completed several
technical courses relating reservoir management, well
completion and production engineering at Saudi Aramco’s
Upstream Professional Development Center, Dhahran,
Saudi Arabia.
Fadel A. Al-Ghurairi is a Petroleum
Engineering Consultant and Technical
Support Unit Supervisor working on
gas fields. He has 24 years of
experience in production and reservoir
engineering. In the last 12 years, Fadel
has specialized in stimulation and
fracturing
gas wells.
f t i off deep
d
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Deploying Global Competition by Innovation
Network for Empowering Entrepreneurship,
Venturing and Local Business Development:
A Case Study — Desalination Using
Renewable Energy
Author: Dr. M. Rashid Khan
The concept of open innovation (OI) became popular during
the last decade. OI allowed companies to leverage global
sourcing to create business value, keeping in mind that good
ideas are widely distributed since not all of the smartest people
in the world work for any single company. Chesbrough
(2003)1 introduced the OI term to address the needs of mostly
technology-focused R&D departments in large companies that
were “closed” and highly secretive. It has long been recognized
that opening the doors of large companies to outside input and
encouraging an exchange of information will stimulate internal
innovation2-6. The OI practices of large manufacturing companies, such as GE, P&G, Philips, Xerox and IBM, are widely
documented7. As the goal of OI is to source the best innovations
from anywhere in the world, large companies seeking to address
a specific challenge and to deploy internal solutions externally
deliberately introduced OI practices. Can this concept be extended to smaller entities, such as small- and medium-sized
enterprises (SMEs) and entrepreneurs? Can the concept of OI
be applied to encourage regional development by supporting
local entrepreneurship and venturing?
In a paradigm shift, Saudi Aramco Entrepreneurship (AEC)
has initiated an innovation competition with multiple goals directed at addressing the needs of large organizations, SMEs and
individual entrepreneurs, and identifying venture opportunity
needs. The new business model, via the innovation competition,
strives to create value through global participation.
Large companies have successfully used innovation competitions as the primary avenue to pursue OI to fill their internal
R&D voids. In the paradigm shifted model, coined “Innovation
Network” (IN), innovation can be viewed from the perspective
of not only large companies, but also numerous types/sizes of
organizations with diverse roles and needs. In this model, OI
can become relevant to entrepreneurs, startups and the organizations that support them as well as other stakeholders. Small
companies can benefit in different ways from an innovation
competition if it is designed effectively. This article highlights
the “why” and “how” AEC with other stakeholders has used
IN by launching a global competition.
First, cost savings and control can be a significant benefit.
When innovation competition is tightly restricted to one
company, only the sponsor extracts the benefits. When organizations innovate “jointly” via IN through a global competition, a
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greater value can be created at lower costs. In this model, different partners can work on different parts of the challenge and
share expenses for the research and prototypes, deriving different
benefits as appropriate. A significant argument for such a network model is that most entrepreneurs or SMEs do not have
the needed internal technological competencies or resources.
The vital strategic components of intellectual capital8, 9 for
SMEs or entrepreneurs — talent, teams and technology (the 3
Ts)7, 8 — often are not fully explored because of resource limits. The new IN model may allow participants to overcome this
limit by leveraging the commercial value of technologies that
exist in other organizations or that had been co-developed by
teaming with talented partners.
Second, multidisciplinary and cross-industry collaboration
around a common challenge with multiple objectives enhances
creativity among the partners involved. Although a rarely used
technique among SMEs, this approach can spark the search for
more innovative products, services and related concepts.
Third, the partnering of SMEs and/or entrepreneurial organizations with large companies may benefit from the use of
“spillover technology” that is not necessarily relevant for large
companies, but might be of interest to smaller ones, entrepreneurs and other vested groups. The concept of OI cannot be
applied to capture the typical large company benefits — such
as sharing costs and risks, faster product introduction, etc. —
for entrepreneurs or SMEs. Instead, SMEs historically have engaged (or often have been forced into) innovation via a network as a consequence of major shifts in their business model,
whether to seize new business opportunities and/or to boost
profitability, or merely to survive. When they confront such a
shift, their limited financial and human resources and their
lack of technological capabilities often force them to look for
different types of innovation partners.
The key to success for technology development or economic
development via innovation depends on (1) Identifying the
strategic drivers to address the greatest needs or challenges for
all, (2) Engaging stakeholders and obtaining their buy-ins, (3)
Implementing or conducting an approach to the challenge in the
most effective manner to derive maximum benefit for all partners
and stockholders, and finally, (4) Deploying solutions by engaging partners and collaborators. Managing relationships with individual partners and organizing the overall network of diverse
innovation partners is critical to success, since collaborative innovation is easier with partners of similar size and ambitions.
This careful management of relations and needs is paramount
and is more challenging than when an OI model is focused on
one goal and a single company. A case study of innovation that
addressed a regional challenge with global input and an added
goal to further entrepreneurship is provided in this article, with
careful consideration of all four elements listed above.
To help Saudi Arabia meet its ever-growing need for potable
water and to foster a culture of technology-based entrepreneurship in the Kingdom, the AEC and GE in April 2014 launched
a global competition in the area of seawater desalination, with
a particular focus on using renewable energy. What is the link
between innovation and entrepreneurship? Why did AEC,
which is focused on regional business development, get involved in such a global topic? What are the justifications for
AEC’s co-sponsorship of this global innovation competition?
First, the desalination topic addresses one of the greatest
technical and business challenges of our time, and addressing
and fulfilling a need is fundamental to entrepreneurship development. Saudi Arabia is considered to be among the poorest
countries in the world in terms of natural renewable water resources, and it depends upon energy-intensive water desalination
plants and its rapidly depleting groundwater reserves to meet
its fast-growing water needs. The Kingdom is the world’s
largest producer of desalinated water, which meets over 70% of
its present drinking water needs. Over 50 cities and distribution
centers in Saudi Arabia receive their water from these plants. The
state-owned Saline Water Conversion Corporation (SWCC)
operates 36 desalination stations, and independent power and
water producers supplement these. SWCC would like to see a
greater participation by the private sector, and therefore, views
further development as an opportunity for entrepreneurs and
local venturing. Using this initiative of global competition by IN,
the AEC hopes not only to solicit innovative solutions but also to
develop and deploy those solutions here in the Kingdom through
collaboration between both national and global innovators.
Therefore, the innovation competition was conceived with
broader perspectives in mind, and the challenge was accordingly developed with partners and stakeholders to address the
greatest technical need of the region, engaging SWCC, King
Abdulaziz City for Science and Technology (KACST) and all
key local universities. In the formulation of the competition,
many avenues were explored, and many service providers were
considered. Partnership with GE appeared to be the most economic and efficient way to achieve the most desirable results.
The ultimate scope of the challenge developed by AEC, which
served as the “main hub” of the innovation network, addressed
the somewhat competing needs of all partners/stakeholders.
The competition has attracted 108 proposals from global
experts with multidisciplinary backgrounds with respect to
geographic distribution (32 countries), organization type and
experience (with combined input reflecting nearly 200
patents/peer-reviewed publications by over 100 Ph.D.s and
other advanced professionals). Based on the initial assessments, many proposals address the needs of the stakeholders
(SWCC, GE, Saudi Aramco, Saudi Aramco Energy Ventures
(SAEV), AEC and in-Kingdom entrepreneurs). Subsequent dialogues among technology leaders in this strategic area may allow
SAEV, SWCC, AEC and others to develop partnerships with
global innovative companies having cutting-edge solutions for
possible venturing and local deployment.
Second, in Saudi Arabia, significant investment funding has
been allocated to increasing potable water, creating opportunities
for entrepreneurship and venturing. As the largest user of desalination processes and technology in the world, Saudi Arabia is
projected to spend about $50 billion on seawater desalination
technologies in the coming decade and to invest around $100
billion in solar energy. Current desalination techniques are energy
intensive. To fuel desalination, Saudi Arabia is burning the
equivalent of 1.5 million barrels of oil per day of precious fuels.
An increase in energy efficiency and/or a reduction in energy
consumption is the key to ensuring that the Kingdom receives
the most value for its natural resources — value that can be used
to develop the Kingdom and its people. As a result, the networkbased initiative by AEC received significant support at the outset
from SWCC, the main proponent for the Kingdom’s desalination.
Fig. 1. Number of patents filed worldwide related to “Osmotic Derived Membrane
Process,” just one of many types of desalination methods commercially used.
Source: International Desalination Report (IDS), September 2014.
Fig. 2. The submissions came from 32 countries with 108 proposals, the largest
number from the U.S. and the second largest input from Saudi Arabia.
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71
Third, successful entrepreneurs welcome the best concepts
that address a critical need no matter where the solutions come
from. As a result, the AEC charter encourages AEC to engage
in activities in or outside Saudi Arabia in realizing its key
objective, that of promoting entrepreneurship. According to
many experts — as described in many textbooks — an entrepreneur is a person who converts an innovation into a business,
no matter where the innovation originates. Khalid A. Al-Falih7,
president and CEO of Saudi Aramco, routinely links entrepreneurship with innovation. Useful technology and know-how
today is widely distributed and is increasing in a rapid manner,
Fig. 1, and no individual organization — no matter how capable
or how big — can innovate effectively on its own. Despite being
the first one organized by Saudi Aramco, the global innovation
competition generated a large number of quality responses, including a sizeable number from Saudi Arabia. It is clear that
the Kingdom and the company can save energy and financial
resources by applying creative new technologies and processes.
The largest number of country-based submissions came from
the U.S. (38 submissions), followed by Saudi Arabia (nine submissions), Fig. 2. The proposals received careful review by
multidisciplinary teams in SWCC, GE and Saudi Aramco to
identify those solutions that best address the critical needs of
the region and that can be readily deployed via entrepreneurship
and venturing in Saudi Arabia, in addition to fulfilling the mission of SWCC and GE.
SUMMARY
Entrepreneurship is always heightened by new technologies.
The innovation competition generated many concepts of value
for all of the parties concerned. The broader perspective of innovation so defined can be used to extract multiple benefits
from larger organizations, such as SWCC, Saudi Aramco and
GE, as well as from the smaller entities such as local entrepreneurs, SMEs and those engaged in local venture development.
The broader perspective of the IN model should be far more
effective than traditional OI. That is because the IN incorporates the perspective of regional innovation as involving many
diverse players, including local research centers for fundamental, basic and applied research; business ecosystems for both
established companies and startups; government institutions
and entrepreneurs; and agents of technology transfer and
startup incubators.
Saudi Arabia is in need of cost-effective and energy-effective
technologies for producing desalinated water. In the past, water
production and security of supply drove technology selection.
Because energy costs were low, proven, established technologies
tended to be preferred over innovative solutions. This global
competition, which focuses on the use of abundant renewable
energy — such as solar — brings greater innovation to this
critical area, and there are plans to introduce efficient new
technologies in stations nearing the end of their life span, both
to extend their productive life and to test new technologies.
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Applying the newer model, global innovation has the potential
to present alternatives from key experts around the world to
expand the technology options for Saudi Arabian organizations, which they can then develop, leverage and deploy in the
future, empowering regional entrepreneurship.
Finally, the network model of innovation conducted via a
global competition not only will assist the stakeholders, such
as SWCC, Saudi Aramco and GE, but will also enable venture
development and entrepreneurship. The contest was developed
keeping localization in mind in collaboration with the key local
stakeholders, such as SWCC, KACST and others. As an example of support, SWCC offered to locally facilitate the testing
and deployment of those technologies with high potential, and
to serve as a key stakeholder for the initiative.
Desalination and renewables are among the greatest challenges
for the Kingdom, as defined by KACST, following the directive
of the Custodian of the Two Holy Mosques King ‘Abd Allah
ibn ‘Abd Al-’Aziz Al Sa’ud. Therefore, the innovative concepts
gained from the competition can be localized to create highvalue new local businesses and high value jobs in Saudi Arabia.
REFERENCES
1. Chesbrough, H.: Open Innovation, Harvard Business
School Press, Cambridge, MA, 2003, 227 p.
2. Tilton, J.: International Diffusion of Technology: The Case
of Semiconductors, Brookings Institute, Washington, D.C.,
1971, 183 p.
3. Allen, T.J.: Managing Flow of Technology, The MIT Press,
Cambridge, MA, 1977, 334 p.
4. Tidd, J.: “Conjoint Innovation: Building a Bridge between
Innovation and Entrepreneurship,” International Journal of
Innovation Management, Vol. 18, No. 1, February 2014.
5. Rothwell, R. and Zegveld, W.: Reindustrialization and
Technology, Longman, London (Harlow), 1985, 282 p.
6. Khan, M.R.: “Some Insights into Embracing an Innovation
Competition to Identify Breakthrough Technologies or
Processes,” Saudi Aramco Journal of Technology, Fall 2010.
7. “MIT and Saudi Aramco Augment Existing Collaboration:
More Energy Research,” MOU signed by MIT and Saudi
Aramco, June 18, 2012. http://mitei.mit.edu/news/mit-andsaudi-aramco-augment-existing-collaboration.
8. Khan, M.R. and Germeraad, P.: “Management of
Innovation and Intellectual Capital: The Concept of Three
T’s for Growth and Sustainability for an Organization and
a Nation,” Les Nouvelles, March 2011, pp. 26-38.
9. Khursani, S.A., Bazuhair, O.S. and Khan, M.R.: “Strategy
for the Rapid Transformation of Saudi Arabia by
Leveraging Intellectual Capital and Knowledge
Management,” Saudi Aramco Journal of Technology,
Winter 2011.
BIOGRAPHY
Dr. M. Rashid Khan is Head of
Intellectual Property and Innovation
for Saudi Aramco Entrepreneurship,
where he launched the first Global
Innovation Competition for Saudi
Aramco. Previously, he served as the
Deputy Director of the Technology
Program of Engineering Services and was a
Management Progra
member of the Intellectual Assets and Innovation
Management Group from the onset of these programs.
Rashid shaped the first Intellectual Property (IP) policy for
King Abdullah University of Science and Technology
(KAUST), and defined the IP strategy in executing several
technology transfer agreements, while also serving as the
key technical reviewer.
He has extensive work experience in upstream,
downstream and other diverse areas of the oil and gas
industry. Rashid has served as a “Distinguished Lecturer”
for the Society of Petroleum Engineers (SPE) and presented
many invited lectures, including at Harvard and MIT. He
served as a mentor for the MIT Energy Competition and
Licensing Executive Business Competition, and taught a
course on patent monetization at MIT. Rashid also taught a
course on Entrepreneurship at King Fahd University of
Petroleum and Minerals (KFUPM).
He received Texaco’s highest technical award for
creativity. Rashid also received the American Chemical
Society Texaco Research Award. Additionally, he served as
a Technical Advisor to the U.S. White House; was an
Adjunct Professor for Vassar College, Poughkeepsie, NY;
and served in the United Nations Development Program
(UNDP). Rashid has around 30 patent awards and has
published over 200 journal papers. He has edited or
authored six books in the areas of energy, environment,
innovation, IP and business development.
Rashid received his M.S. in Environmental Engineering
from Oregon State University, Corvallis, OR, in 1979 and
his Ph.D. degree in Energy and Fuels Engineering from
Pennsylvania State University, University Park, PA, in 1984.
He was recognized as a “Distinguished Fellow” by the
President of Licensing Executive Society. Rashid is a
Certified Patent Licensing Professional.
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2014 SAUDI ARAMCO PATENTS GRANTED LIST
CLAY ADDITIVE FOR REDUCTION OF SULFUR IN
CATALYTICALLY CRACKED GASOLINE
Granted Patent: U.S. 8,623,199, Grant Date: January 7, 2014
Abdennour Bourane, Omer R. Koseoglu, Musaed Al-Ghrami,
Christopher Dean, Mohammed A. Siddiqui and Shakeel Ahmed
Summary
The patent relates to the reduction of sulfur in gasoline
produced in a fluid catalytic cracking process, and more
particularly, to a method and sulfur reduction additive
composition for use in the fluid catalytic cracking process.
HYDRATED NIOBIUM OXIDE NANOPARTICLE
CONTAINING CATALYSTS FOR OLEFIN HYDRATION
Abdennour Bourane, Stephan R. Vogel and Wei Xu
process that includes permutable reactors and that is capable of operating at moderate temperature and pressure
with reduced hydrogen consumption.
DETERMINATION OF ROCK MECHANICS FROM
APPLIED FORCE TO AREA MEASURES WHILE
SLABBING CORE SAMPLES
Mohammad Ameen
Summary
The patent relates to rock material characterization, and
in particular, to characterization of mechanical properties
of formation rock from hydrocarbon reservoirs for geological and engineering purposes, such as design and
planning of well completion, well testing and formation
stimulation.
Summary
The patent relates to a catalyst and method of preparing a
catalyst for olefin hydration. More specifically, the invention relates to a catalyst and method of preparing a catalyst wherein the catalyst includes amorphous or crystalline
nanoparticles of hydrated niobium oxide, niobium oxosulfate, niobium oxo-phosphate or mixtures thereof for
use in the hydration of olefins.
METHOD FOR PREPARING POLYPROPYLENE FILMS
HAVING IMPROVED ULTRAVIOLET RADIATION
STABILITY AND SERVICE LIFE
Ahmed Basfar, Khondoker Ali, Milind M. Vaidya and
Ahmed Bahamdan
Summary
The patent relates to a polyolefin resin and articles prepared from the polyolefin resin. More specifically, the
invention relates to a polypropylene resin exhibiting improved ultraviolet radiation stability and articles prepared
therefrom.
PROCESS FOR CATALYTIC HYDROTREATING OF
SOUR CRUDE OILS
Stephane Kressmann, Raheel Shafi, Esam Hamad and
Bashir M. Dabbousi
Summary
The patent relates to a pre-refining process for the desulfurization of sour crude oils using a catalytic hydrotreating
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METHOD FOR REMOVING MERCURY FROM A
GASEOUS OR LIQUID STREAM
Granted Patent: U.S. 8,641,890, Grant Date: February 4, 2014
Feras Hamad, Ahmed A. Bahamdan, Abdulaziz Al-Mulhim,
Ayman Rashwan and Bandar A. Fadhel
Summary
The patent relates to an apparatus and method for removing mercury or mercury containing compounds from
fluids, e.g., liquids, gases and gaseous condensates. More
particularly, it relates to the use of porous membranes and
scrubbing solutions, which when used in tandem remove
mercury from the aforementioned fluids.
RECOVERY OF HEAVY OIL THROUGH THE USE OF
MICROWAVE HEATING IN HORIZONTAL WELLS
Khaled Al-Buraik
Summary
The patent relates to a method of extracting and recovering subsurface sour crude oil deposits. More specifically,
the method employs microwave radiation and the permeability enhancement of reservoir rocks due to fracture by
selective heating and due to the creation of critical and
supercritical fluids in the subsurface area.
SYSTEM AND METHOD FOR IMPROVED
COORDINATION BETWEEN CONTROL AND
SAFETY SYSTEMS
Abdelghani A. Daraiseh and Patrick S. Flanders
Summary
The patent relates to regulatory control systems and safety
shutdown systems, and methods for monitoring and controlling field devices used with commercial and industrial
processes. In particular, it relates to systems and methods
for improved coordination between control and safety
systems.
a subterranean hydrocarbon producing well. More specifically, the invention relates to an apparatus for the staging
of cement between the casing and a wellbore.
CATALYTIC PROCESS FOR DEEP OXIDATIVE
DESULFURIZATION OF LIQUID TRANSPORTATION
FUELS
CATHODIC PROTECTION ASSESSMENT PROBE
Granted Patent: U.S. 8,663,459, Grant Date: March 4, 2014
Farhan M. Al-Shahrani, Gary Martinie, Tiancun Xiao and
Malcolm Green
Darrell Catte
Summary
Summary
The patent relates to an apparatus and method for use
with a corrosion monitoring and/or mitigation system.
More specifically, the invention relates to an apparatus
and method for monitoring cathodic protection while supplying cathodic protection power to an object being protected. Yet more specifically, the invention relates to a
system for determining electrolyte corrosivity and optimum site-specific cathodic protection operating levels.
SULFUR STEEL-SLAG AGGREGATE CONCRETE
Mohammed Al-Mehthel, Saleh Al-Idi, Mohammed Maslehuddin,
Mohammed R. Ali and Mohammed S. Barry
Summary
The patent relates to a composition and method for disposing of sulfur by using it to produce a sulfur-based
concrete.
INTEGRATED HYDROTREATING AND OXIDATIVE
DESULFURIZATION PROCESS
The patent relates to novel catalysts, systems and
processes for the reduction of the sulfur content of liquid
hydrocarbon fractions of transportation fuels, including
gasoline and diesel fuels, to about 10 ppm or less by an
oxidative reaction.
ECONOMICAL HEAVY CONCRETE WEIGHT
COATING FOR SUBMARINE PIPELINES
Mohammed Al-Mehthel, Bakr Hammad, Alaeddin Al-Sharif,
Mohammed Maslehuddin and Mohammed Ibrahim
Summary
The patent relates to the field of submarine pipelines. In
particular, the invention is directed to an economical
heavy concrete weight coating used to keep the submarine
pipeline submerged below the surface of the water.
MACHINES, COMPUTER PROGRAM PRODUCTS
AND COMPUTER-IMPLEMENTED METHODS
PROVIDING AN INTEGRATED NODE FOR DATA
ACQUISITION AND CONTROL
Omer R. Koseoglu and Abdennour Bourane
Soliman M. Almadi, Soliman A. Al-Walaie and
Tofig A. Al-Dhubaib
Summary
Summary
The patent relates to desulfurization of hydrocarbon
streams, and in particular, to a system and process for integrated hydrotreating and oxidative desulfurization of
hydrocarbon streams to produce reduced sulfur content
hydrocarbon fuels.
The patent relates to automated industrial processes. In
particular, the invention relates to the control of and the
acquisition of data from, remote and in-plant subsystems
in automated industrial processes.
SLIDING STAGE CEMENTING TOOL
Shaohua Zhou
Summary
PLUGGING THIEF ZONES AND FRACTURES BY IN
SITU AND IN-DEPTH CRYSTALLIZATION FOR
IMPROVING WATER SWEEP EFFICIENCY OF
SANDSTONE AND CARBONATE RESERVOIRS
Xianmin Zhou and Yun C. Chang
The patent relates to an apparatus for use while completing
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Summary
The patent relates to compositions and methods for treating subterranean formations. More specifically, the invention relates to compositions and methods for plugging
thief zones and fractures in subterranean formations.
SUPER-RESOLUTION FORMATION FLUID IMAGING
Howard K. Schmidt
Summary
The patent relates to imaging subsurface structures, particularly hydrocarbon reservoirs and fluids therein; it relates
more particularly to cross-well and borehole to surface
electromagnetic (BSEM) surveying.
BUOYANT PLUG FOR EMERGENCY DRAIN IN
FLOATING ROOF TANK
bases. More specifically, it relates to providing continuous
monitoring for leaks and pressure losses in fuel pipelines,
as well as providing status indications for, and control of,
jet fuel supply valves, isolation valves, jet fuel pumps and
other instrumentation in jet fuel piping systems.
BOREHOLE TO SURFACE ELECTROMAGNETIC
TRANSMITTER
Alberto F. Marsala, Mohammad Al-Buali, Zhanxiang He and
Tang Biyan
Summary
The patent relates to an electromagnetic energy source or
transmitter for borehole to surface electromagnetic surveying and mapping of subsurface formations.
ZERO LEAKOFF GEL
Nassir S. Al-Subaiey
Granted Patent: U.S. 8,684,081, Grant Date: April 1, 2014
Saleh Al-Mutairi, Ali Al-Aamri, Khalid Al-Dossary and
Mubarak Al-Dhufairi
Summary
Summary
The patent relates to floating roofs for storage tanks that
contain volatile fluid, and more particularly, to an emergency drain valve for water accumulated atop a double
deck roof.
The patent relates to a silicate gel composition formed in
situ and its method of use. More specifically, it relates to a
silicate gel composition that forms in a wellbore and a
method of diverting treatment fluid in a wellbore.
WELL SYSTEM WITH LATERAL MAIN BORE AND
STRATEGICALLY DISPOSED LATERAL BORES AND
METHOD OF FORMING
METHODS FOR PERFORMING A FULLY
AUTOMATED WORKFLOW FOR WELL
PERFORMANCE MODEL CREATION AND
CALIBRATION
Fahad M. Al-Ajmi and Ahmed H. Alhuthali
Ahmad Al-Shammari
Summary
Summary
The patent relates to a subterranean hydrocarbon producing well system. More specifically, the invention relates to
a well system having a main bore that extends above a
producing formation with lateral bores that depend from
the main bore and intersect the producing formation.
PIPELINE LEAK DETECTION AND LOCATION
SYSTEM THROUGH PRESSURE AND CATHODIC
PROTECTION SOIL
Pablo D. Genta
Summary
The patent relates to the detection and location of fuel
leakages occurring in underground jet fuel piping systems
of the type employed at civil airports and military air
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The patent relates to oil and gas recovery. In particular, it
relates to the optimization of production and injection
rates, and more specifically to systems, program product
and methods that provide improved well performance
modeling, building and calibration.
WELLBORE PRESSURE CONTROL DEVICE
Mohamed N. Noui-Mehidi
Summary
The patent relates to an apparatus and method for managing pressure in a wellbore. More specifically, the invention
relates to the use of swirling fluids to maintain a wellbore
at a desired pressure.
CONVERTING HEAVY SOUR CRUDE OIL/
EMULSION TO LIGHTER CRUDE OIL USING
CAVITATIONS AND FILTRATION-BASED SYSTEMS
PIPELINE PIG WITH INTERNAL FLOW CAVITY
M. Rashid Khan
Summary
Summary
The patent relates to pipeline pigs used in the inspection of
pipelines.
The patent relates to the conversion of heavier sulfur-containing crude oil into lighter crude oil with lower sulfur
content and lower molecular weight than the original
crude oil.
SOUR GAS AND ACID NATURAL GAS SEPARATION
MEMBRANE PROCESS BY PRE-REMOVAL OF
DISSOLVED ELEMENTAL SULFUR FOR PLUGGING
PREVENTION
Milind M. Vaidya, Jean-Pierre Ballaguet, Sebastien Duval and
Anwar Khawajah
Summary
Granted Patent: U.S. 8,715,423, Grant Date: May 6, 2014
Ali Al-Mousa
PROCESS FOR OXIDATIVE CONVERSION OF
ORGANOSULFUR COMPOUNDS IN LIQUID
HYDROCARBON MIXTURES
Gary D. Martinie, Farhan M. Al-Shahrani and
Bashir M. Dabbousi
Summary
The patent relates to the conversion of organosulfur compounds in liquid hydrocarbon mixtures, and more particularly, their conversion by catalytic oxidation.
SLIDING STAGE CEMENTING TOOL AND METHOD
The patent relates to methods for removing sulfur from
gas streams prior to sending the gas streams to gas separation membranes.
Shaohua Zhou
SIMULTANEOUS WAVELET EXTRACTION AND
DECONVOLUTION IN THE TIME DOMAIN
The patent relates to an apparatus for use while completing a subterranean hydrocarbon producing well. More
specifically, the invention relates to an apparatus for the
staging of cement between the casing and a wellbore.
Saleh Al-Dossary and Jinsong Wang
Summary
The patent relates to seismic data processing and more
particularly, to wavelet extraction and deconvolution
during seismic data processing.
METHODS FOR MANAGING CONTRACT
PROCUREMENT
Hisham Al-Abdulqader, Ammar Al-Mubarak and Udai Al-Mulla
Summary
The patent relates to automated business transaction systems, in particular to contract management systems. More
specifically, this patent relates to a system, program product and methods of facilitating contract procurement and
contract management through an online contract procurement and management website.
Summary
ASPHALT COMPOSITIONS WITH SULFUR
MODIFIED POLYVINYL ACETATE (PVAC)
Mohammed Al-Mehthel, Saleh Al-Idi, Ibnelwaleed Hussein,
Hamad Al-Abdulwahhab and Mohammed Suleiman
Summary
The patent relates to asphalt compositions containing asphalt and sulfur modified polyvinyl acetate polymers having improved properties relative to unmodified polyvinyl
acetate polymers.
WASTEWATER TREATMENT PROCESS INCLUDING
IRRADIATION OF PRIMARY SOLIDS
William Conner, Osama I. Fageeha and Thomas Schultz
Summary
The patent relates to a system and method for wastewater
treatment.
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PRODUCTION OF SYNTHESIS GAS FROM SOLVENT
DEASPHALTING PROCESS BOTTOMS IN A
MEMBRANE WALL GASIFICATION REACTOR
Omer R. Koseoglu
Summary
The patent relates to processes for the partial oxidation in
a membrane wall gasification reactor of heavy bottoms,
which can also contain waste materials, recovered from a
solvent deasphalting unit operation to produce a high
value synthesis gas.
SULFUR MODIFIED ASPHALT FOR WARM MIX
APPLICATIONS
Milind Vidya, Anwar H. Khawajah, Rashid M. Othman and
Laurand Lewandowski
Summary
The patent relates to an asphalt concrete mixture, an asphalt binder composition and methods of preparing the
asphalt concrete mixture.
WELLHEAD HIPS WITH AUTOMATIC TESTING AND
SELF-DIAGNOSTICS
Patrick S. Flanders
Summary
The patent relates to a method and an apparatus for the
operation and testing of a high integrity protection system
(HIPS) connected to a wellhead pipeline system.
APPARATUS AND METHODS FOR ENHANCED
WELL CONTROL IN SLIM COMPLETIONS
Mohamed N. Noui-Mehidi and Jinjiang Xiao
Summary
The patent relates to well control of hydrocarbon wells.
More particularly, the invention relates to well control of
a slim-hole well.
CLUSTER 3D PETROPHYSICAL UNCERTAINTY
MODELING
Roger R. Sung and Khalid S. Al-Wahabi
Summary
The patent relates to computerized simulation of
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hydrocarbon reservoirs in the earth that have been modeled as a three-dimensional grid of cells. In particular, it
relates to the determination of reservoir attributes or
properties on a cell-by-cell basis for the individual cells in
the reservoir model.
SYSTEMS AND PROGRAM PRODUCT FOR
PERFORMING A FULLY AUTOMATED WORKFLOW
FOR WELL PERFORMANCE MODEL CREATION
AND CALIBRATION
Ahmad Al-Shammari
Summary
The patent relates to oil and gas recovery, in particular to
the optimization of production and injection rates. More
specifically, it relates to systems, program product and
methods that provide improved well performance modeling, building and calibration.
INDUCING FLOW BACK OF DAMAGING MUDINDUCED MATERIALS AND DEBRIS TO IMPROVE
ACID STIMULATION OF LONG HORIZONTAL
INJECTION WELLS IN TIGHT CARBONATE
FORMATIONS
Ali A. Al-Taq
Summary
The patent relates to a method of conditioning a long horizontal open hole water injection well in a tight formation
prior to acid stimulation to improve the contact of the
acid with the rock as well as the penetration of the acidic
materials into the reservoir rock, and thereby enhancing
the permeability of the formation and the flow rate of the
injected water.
DETERMINATION OF ANGLE OF INTERNAL
FRICTION OF FORMATION ROCK WHILE SLABBING
CORE SAMPLES
Mohammed S. Ameen
Summary
The patent relates to rock material characterization, and
in particular, to the characterization of the mechanical
properties of formation rock from hydrocarbon reservoirs
for geological and engineering purposes, such as design
and planning of well completion, well testing and formation stimulation.
INTEGRATED DESULFURIZATION AND DENITRIFICATION PROCESS INCLUDING MILD HYDROTREATING AND OXIDATION OF AROMATIC-RICH
HYDROTREATED PRODUCTS
AUXILIARY PRESSURE RELIEF RESERVOIR FOR
CRASH BARRIER
Granted Patent: U.S. 8,741,127, Grant Date: June 3, 2014
Omer R. Koseoglu, Abdennour Bourane, Farhan M. Al-Shahrani
and Emad Al-Shafi
Summary
Summary
The patent relates to integrated oxidation processes to efficiently reduce the sulfur and nitrogen content of hydrocarbons to produce fuels having reduced sulfur and
nitrogen levels.
INTEGRATED DESULFURIZATION AND DENITRIFICATION PROCESS INCLUDING MILD HYDROTREATING OF AROMATIC-LEAN FRACTION AND
OXIDATION OF AROMATIC-RICH FRACTION
Omer R. Koseoglu, Abdennour Bourane, Farhan M. Al-Shahrani
and Emad Al-Shafi
Summary
The patent relates to integrated oxidation processes to efficiently reduce the sulfur and nitrogen content of hydrocarbons to produce fuels having reduced sulfur and
nitrogen levels.
METHODS OF PREPARING LIQUID BLENDS FOR
BUILDING CALIBRATION CURVES FOR THE EFFECT
OF CONCENTRATION ON LASER-INDUCED
FLUORESCENCE INTENSITY
Ezzat M. Hegazi and Abdullah H. Al-Grainees
Summary
The patent relates to a small volume apparatus and a trialand-error method for identifying and replicating original
target liquid blends of unknown ratios by employing laserinduced fluorescence spectroscopy.
STORAGE TANK FLOATING ROOF SUMP WITH
EMERGENCY OVERFLOW
Mohammed Ben Afeef
Summary
The patent relates to a drainage device for use on a floating roof of a storage tank for liquid products.
Bandar Al-Qahtani
The patent relates to hydraulically powered vehicle crash
barrier systems, in particular vehicle crash barrier systems
having an emergency mode of operation to rapidly raise
the crash barrier.
DISPOSAL OF SULFUR THROUGH USE AS SANDSULFUR MORTAR
Mohammed Al-Mehthel, Saleh Al-Idi, Mohammed Maslehuddin,
Mohammed R. Ali and Mohammed S. Barry
Summary
The patent relates to a composition and method for disposing of sulfur by converting waste sulfur to a useful
product, namely, by producing a sulfur-based mortar.
IONIC LIQUID DESULFURIZATION PROCESS
INCORPORATED IN A LOW PRESSURE SEPARATOR
Omer R. Koseoglu and Adnan Al-Hajji
Summary
The patent relates to a system and process for desulfurizing hydrocarbon fractions, and in particular, to a system
and process that integrates ionic liquid extractive desulfurization with a hydroprocessing reactor.
SEISMIC IMAGE FILTERING MACHINE TO
GENERATE A FILTERED SEISMIC IMAGE,
PROGRAM PRODUCTS AND RELATED METHODS
Saleh Al-Saleh
Summary
The patent relates to the field of geophysical subsurface
seismic imaging in geophysical seismic exploration. More
specifically, this invention generally relates to machines,
program products and methods to generate filtered seismic images based on seismic image data filtered by attenuating coherent noise from unfiltered seismic image data
using a plurality of nonstationary convolution operators
as local filters at each spatial location of an unfiltered
seismic image wavefield.
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PERFORMANCE GRADED, SULFUR MODIFIED
ASPHALT COMPOSITIONS FOR SUPER PAVE
COMPLIANT PAVEMENTS
Granted Patent: U.S. 8,772,380, Grant Date: July 8, 2014
Milind M. Vaidya, Anwar H. Khawajah, Rashid M. Othman and
Laurand Lewandowski
Summary
The patent relates to an asphalt concrete mixture, an asphalt binder composition and methods of preparing the
asphalt concrete mixture.
SAND PRODUCTION CONTROL THROUGH THE
USE OF MAGNETIC FORCES
Ashraf M. Al-Tahini
Summary
The patent relates to a method for controlling the amount
of sand produced from a wellbore. More particularly, the
invention relates to a method of using magnetic forces to
control the flow of loose sand particles within an underground formation to prevent the loose sand particles from
damaging downhole tools.
BLOCKED VALVE ISOLATION TOOL
Granted Patent: U.S. 8,800,602, Grant Date: August 12, 2014
Mohammad Al-Shammary
Summary
The patent relates to the field of gas treatment and production facilities, and particularly to the procedures employed in a portion of a gas flow duct system for isolation
and removal of a valve for inspection, repair or replacement.
METHOD FOR REAL-TIME MONITORING AND
TRANSMITTING HYDRAULIC FRACTURE SEISMIC
EVENTS TO SURFACE USING THE PILOT HOLE OF
THE TREATMENT WELL AS THE MONITORING
WELL
Kirk M. Bartko and Brett W. Bouldin
Summary
WATER SELF-SHUTOFF TUBULAR
The patent relates to the field of hydraulic fracturing,
monitoring and data transmission of microseismic information from a zone of interest within a reservoir. More
particularly, it relates to the utilization and employment of
electrically and physically isolated downhole acoustic
monitoring equipment within a fracturing treatment well
to detect microseismic events during fracturing operations.
Mohammad Al-Shammary
PARTIALLY RETRIEVABLE SAFETY VALVE
Brett W. Bouldin and Stephen Smith
Summary
The patent relates to controlling the production of oil and
gas reservoirs. More specifically, the invention relates to
an apparatus and method for controlling water production with a multilayered tubular and a water sensitive
composite.
INTEGRATED DEASPHALTING AND OXIDATIVE
REMOVAL OF HETEROATOM HYDROCARBON
COMPOUNDS FROM LIQUID HYDROCARBON
FEEDSTOCKS
Summary
The patent relates to oxidative desulfurization, and more
particularly, to a process for integrated deasphalting and
oxidative removal of heteroatom-containing hydrocarbon
compounds, such as organosulfur compounds, of liquid
hydrocarbon feedstocks.
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Summary
The patent relates to deep-set safety valves used in subterranean well production. More specifically, the invention
relates to deep-set safety valves used in connection with
submersible pumps for controlling a well.
SYSTEM FOR MEASUREMENT OF MOLTEN
SULFUR LEVEL IN RECEPTACLES
Adel S. Al-Misfer
Summary
The patent relates to the measurement and control of the
flow of molten sulfur that is being added to a container or
receptacle, for example, to a steam jacketed tank truck for
transportation or to a sulfur pit for storage.
SOUR GAS AND ACID NATURAL GAS SEPARATION
MEMBRANE PROCESS BY PRE-REMOVAL OF
DISSOLVED ELEMENTAL SULFUR FOR PLUGGING
PREVENTION
Milind M. Vaidya, Jean Pierre Ballaguet, Sebastien A. Duval and
Anwar H. Khawajah
Summary
The patent relates to a process for refining naphtha. More
specifically, embodiments of the invention utilize two isomerization units and a reforming unit to create a gasoline
blend having an improved octane rating as compared to
the naphtha and/or to produce concentrated reformate for
petrochemicals.
Summary
The patent relates to methods for removing sulfur from
gas streams prior to sending the gas streams to gas separation membranes.
CATALYTIC REFORMING PROCESS AND SYSTEM
FOR PRODUCING REDUCED BENZENE GASOLINE
Summary
The patent relates to the catalytic reforming apparatus
and processes, particularly for producing gasoline of
reduced benzene content.
SUPER RESOLUTION FORMATION FLUID IMAGING
DATA ACQUISITION AND PROCESSING
INTEGRATED SYSTEM FOR MONITORING
PERMEATE QUALITY IN WATER TREATMENT
FACILITIES
Nicos Isaias, Ioannis Gragopoulos and Anastasios Karabelas
Summary
The patent relates to a method and apparatus for monitoring permeate quality in a water treatment process. More
specifically, the invention relates to a method and apparatus for monitoring the performance of individual membrane elements in a reverse osmosis or nanofiltration
desalination of a water treatment plant.
DEEP-READING ELECTROMAGNETIC DATA
ACQUISITION METHOD
Howard K. Schmidt
Alberto F. Marsala, Saleh B. Al-Ruwaili, Shouxiang Ma, Michael
Wilt, Steve Crary and Tarek Habashy
Summary
Summary
The patent relates to imaging subsurface structures, particularly hydrocarbon reservoirs and fluids therein; more
particularly, it relates to cross-well and borehole to surface
electromagnetic (BSEM) surveying.
The patent relates to the planning, acquisition, processing
and interpretation of geophysical data, and more particularly, to methods for interpreting deep-reading electromagnetic data acquired during a field survey of the subsurface.
MICROWAVE PROMOTED DESULFURIZATION OF
CRUDE OIL
AUTOMATED METHOD FOR QUALITY CONTROL
AND QUALITY ASSURANCE OF SIZED BRIDGING
MATERIAL
M. Rashid Khan and Emad N. Al-Shafei
Summary
The patent relates to the processing of crude oil using
microwave energy to reduce the sulfur content.
PROCESS DEVELOPMENT BY PARALLEL
OPERATION OF PARAFFIN ISOMERIZATION UNIT
WITH REFORMER
Md. Amanullah, John T. Allen and Mohammed Kilani
Summary
The patent relates to drill-in fluids used in oil and gas
drilling, and in particular, to a laboratory method for evaluating the durability of sized bridging materials used in
the formulation of drill-in fluids to eliminate or minimize
formation damage.
Cemal Ercan, Yuguo Wang, Mohammad Al-Dossary and Rashid
M. Othman
WINTER 2014
81
PROCESS FOR UPGRADING HEAVY AND HIGHLY
WAXY CRUDE OIL WITHOUT SUPPLY OF
HYDROGEN
CIRCULATION AND ROTATION TOOL
Ki-Hyouk Choi
Summary
Summary
The patent relates to a continuous process for upgrading
heavy crude oil and highly waxy crude oil to produce
more valuable crude oil feedstock having a higher API
gravity; lower content of asphaltene, sulfur, nitrogen and
metallic impurities; increased middle distillate yield;
and/or a reduced pour point.
APPARATUS AND METHOD FOR MULTICOMPONENT WELLBORE ELECTRIC FIELD
MEASUREMENTS USING CAPACITIVE SENSORS
Granted Patent: U.S. 8,816,689, Patent Date: August 26, 2014
Daniele Colombo, Timothy H. Keho, Michael A. Jervis and Brett
W. Bouldin
Summary
Granted Patent: U.S. 8,826,992, Grant Date: September 9, 2014
Shaohua Zhou
The patent relates to making up and breaking out pipe
connections during drilling operations. In particular, it relates to a tool for allowing circulation of fluid through,
and rotation of, a pipe string while making up or breaking
out pipe connections.
HYDROCRACKING PROCESS WITH FEED/
BOTTOMS TREATMENT
Omer R. Koseoglu
Summary
The patent relates to hydrocracking processes, and in particular, to hydrocracking processes adapted to receive multiple feedstreams.
SELF-CONTROLLED INFLOW CONTROL DEVICE
The patent relates to an apparatus and method for evaluating oil and gas reservoir characteristics. More specifically, the invention relates to triaxial field sensors for low
frequency electromagnetic fields.
ELECTROCHEMICAL PROMOTION OF CATALYSIS
IN HYDRODESULFURIZATION PROCESSES
Ahmad D. Hammad, Esam Z. Hamad and Mohammed S. Elanany
Summary
The patent relates to the removal of sulfur from hydrocarbon streams, and more particularly, to a catalytic hydrodesulfurization process, which allows for the in situ control of catalyst activity and selectivity.
Shaohua Zhou
Summary
The patent relates to well production devices, and in particular, to a self-controlled inflow control device.
DRILLING, DRILL-IN AND COMPLETION FLUIDS
CONTAINING NANOPARTICLES FOR USE IN OIL
AND GAS FIELD APPLICATIONS AND METHODS
RELATED THERETO
Md. Amanullah and Ziad Al-Abdullatif
Summary
PROCESS FOR UPGRADING HYDROCARBON
FEEDSTOCKS USING SOLID ADSORBENT AND
MEMBRANE SEPARATION OF TREATED PRODUCT
STREAM
The patent relates to drilling, drill-in and completion fluids and related additives for use in oil and gas field applications. More specifically, the invention relates to drilling,
drill-in and completion fluids that include nanoparticles
and related additives.
Omer R. Koseoglu
VALVE ACTUATOR FAULT ANALYSIS SYSTEM
Pablo D. Genta
Summary
The patent relates to the upgrading of hydrocarbon oil
feedstock to remove undesirable sulfur and nitrogen
containing compounds using solid adsorbents.
82
WINTER 2014
Summary
The patent relates to valve actuators, and more specifically, to a fault analysis system for detecting and locating
actuator malfunctions, performance deviations and failures,
as well as causal factors of any such malfunction, performance deviation or failure, to facilitate the determination of adequate remedial actions.
INTEGRATED HYDROTREATING AND
ISOMERIZATION PROCESS WITH AROMATIC
SEPARATION
Granted Patent: U.S. 8,852,426, Grant Date: October 7, 2014
Omer R. Koseoglu
Summary
The patent relates to hydrotreating processes to efficiently
reduce the sulfur content of hydrocarbons.
DEVICE AND METHOD FOR MEASURING
ELEMENTAL SULFUR IN GAS IN GAS LINES
Ihsan Al-Taie, Abdulaziz Al-Mathami and Helal Al-Mutairi
Summary
The patent relates to the sampling of gases, and more particularly, to a device and method for measuring the level
of elemental sulfur present in a gas in a gas line.
STRUCTURE INDEPENDENT ANALYSIS OF 3D
SEISMIC RANDOM NOISE
Saleh Al-Dossary and Yuchun Wang
Summary
The patent relates to the field of image processing and
specifically to the suppression of image data to estimate
and identify random noise in post-stacked three-dimensional seismic data containing geological structures, such
as faults.
WINTER 2014
83
At Saudi Aramco, our passion is enabling opportunity.
From the depths of the earth to the frontiers of the
human mind, we’re dedicated to fostering innovation,
unleashing potential, and applying science to develop
new solutions for the global energy challenge. As the
world’s preeminent energy and chemicals company, it is
our responsibility — our privilege — to maximize the
opportunity available in every hydrocarbon molecule we
produce. That’s how we contribute to our communities,
our industry, and our world. Saudi Aramco is there,
at the intersection of energy and opportunity,
building a better future for all.
84
WINTER 2014
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WINTER 2014
85
GUIDELINES FOR SUBMITTING AN ARTICLE
TO THE SAUDI ARAMCO JOURNAL OF TECHNOLOGY
These guidelines are designed to simplify and help standardize
submissions. They need not be followed rigorously. If you
have additional questions, please feel free to contact us at
Public Relations. Our address and phone numbers are listed
on page 85.
Length
Varies, but an average of 2,500-3,500 words, plus
illustrations/photos and captions. Maximum length should
be 5,000 words. Articles in excess will be shortened.
Acknowledgments
Use to thank those who helped make the article possible.
Illustrations/tables/photos and explanatory text
Submit these separately. Do not place in the text. Positioning
in the text may be indicated with placeholders. Initial
submission may include copies of originals; however,
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acceptable extensions are .TIFF, .JPEG and .PICT.
What to send
Send text in Microsoft Word format via email or on disc, plus
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separately but concurrently, both as email or as hard copy
(more information follows under file formats).
Permission(s) to reprint, if appropriate
Previously published articles are acceptable but can be
published only with written permission from the copyright
holder.
Procedure
Notification of acceptance is usually within three weeks after
the submission deadline. The article will be edited for style
and clarity and returned to the author for review. All articles
are subject to the company’s normal review. No paper can be
published without a signature at the manager level or above.
Format
No single article need include all of the following parts. The
type of article and subject covered will determine which parts
to include.
Working title
Abstract
Usually 100-150 words to summarize the main points.
Author(s)/contributor(s)
Please include a brief biographical statement.
Submission/Acceptance Procedures
Papers are submitted on a competitive basis and are evaluated
by an editorial review board comprised of various department
managers and subject matter experts. Following initial
selection, authors whose papers have been accepted for
publication will be notified by email.
Papers submitted for a particular issue but not accepted for
that issue will be carried forward as submissions for
subsequent issues, unless the author specifically requests in
writing that there be no further consideration. Papers
previously published or presented may be submitted.
Submit articles to:
Introduction
Editor
Different from the abstract in that it “sets the stage” for the
content of the article, rather than telling the reader what it
is about.
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May incorporate subtitles, artwork, photos, etc.
The Saudi Aramco Journal of Technology
C-86, Wing D, Building 9156
Dhahran 31311, Saudi Arabia
Tel: +966-013-876-0498
E-mail: william.bradshaw.1@aramco.com.sa
Submission deadlines
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Assessment of results or restatement of points in introduction.
Endnotes/references/bibliography
Use only when essential. Use author/date citation method in
the main body. Numbered footnotes or endnotes will be
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Standard is The Associated Press Stylebook, 49th ed. and
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86
WINTER 2014
Issue
Paper submission deadline
Release date
Summer 2015
Fall 2015
Winter 2015
Spring 2016
March 1, 2015
June 1, 2015
September 1, 2015
December 1, 2015
June 30, 2015
September 30, 2015
December 31, 2015
March 31, 2016
Additional Content Available Online at: www.saudiaramco.com/jot.com
First Successful Proppant Fracture for Unconventional Carbonate Source Rock in Saudi Arabia
Nayef I. Al Mulhim, Ali H. Al-Saihati, Ahmed M. Al-Hakami, Moataz M. Al-Harbi and Khalid S. Al-Asiri
ABSTRACT
Widely recognized as the world leader in crude oil production, Saudi Aramco has only recently begun to explore for
unconventional gas resources. Saudi Aramco started evaluating its unconventional reservoirs to meet the anticipated future
demands for natural gas. One of the subject plays that is currently being evaluated is a carbonate source rock with nanoDarcy
permeability and very low porosity. The target formation has few, if any, analogs that can be used for comparison. Knowledge
of the formation characteristics, geomechanics, stimulation response and production potential has been nonexistent until
recently.
Well Site Energy Harvesting from High-Pressure Gas Production
Dr. Jinjiang X. Xiao, Wessam A. Busfar, Rafael A. Lastra and Muhammad Adnan
ABSTRACT
Chokes are control valves built into the production systems so that wells can be produced at desired rates, while at the same
time reservoir depletion and sweep can be optimized, and formation and well completion integrity can be protected. The use of
surface chokes also allows surface flow lines and facilities to be designed more economically due to reduced pressure ratings.
Substantial pressure drops can occur through well surface chokes, especially at early stages of production when the reservoir
pressure is still high and lower choke settings are applied. This article investigates energy loss through wellhead chokes for gas
wells, with attention to the laws of thermodynamics.
Optimization and Post-Job Analysis of the First Successful Oil Field Multistage Acid Fracture Treatment in
Saudi Arabia
Tariq A. Al-Mubarak, Majid M. Rafie, Dr. Mohammed A. Bataweel, Rifat Said, Hussain A. Al-Ibrahim, Mohammad F. Al-Hajri, Peter I. Osode,
Abdullah A. Al-Rustum and Omar Al-Dajani
ABSTRACT
Multistage acid fracture treatments are utilized in low permeability carbonate reservoirs (permeability <10 millidarcies (mD)) to
stimulate the formation by creating highly conductive fractures in the formation and bypassing near wellbore damage. The
fracture is generated at high pressures, which are required to break the rock open, while using a viscous pad. The fracture is
then kept open by adding gelled or emulsified acid to create uneven etches on the surface of the fracture.
Microgravity Flood Front Monitoring: Reducing Inversion Ambiguity by Use of Simulation A Priori Data
Stig Lyngra, Dr. Gleb Dyatlov, Dr. Alberto F. Marsala, Antonius M. (Ton) Loermans, Dr. Yuliy A. Dashevsky, Alexandr N. Vasilevskiy,
Dr. Carl M. Edwards and Dr. Daniel T. Georgi
ABSTRACT
Traditional areas using gravimetry methods are surface gravity for mining and oil exploration and bulk density borehole gravity
logging. Large-scale reservoir saturation monitoring is a new application. Substitution of oil or gas by water leads to density
changes in large reservoir volumes, which causes time-dependent gravity field changes.
This article presents a time-lapse gravity data inversion problem for a complex reservoir. The customary bitmap approach
requires many input parameters and results in a well-known inversion ambiguity. The same ambiguity in this work was reduced
by introducing a priori information obtained by biasing the inversion with history matched reservoir simulation data.
On the Cover
Multiple FIB-SEM images were used to construct a 3D characterization for different rock properties in a short turnaround time.
Representative 3D FIB-SEM images were used to quantify mineralogy,
organic matter and porosity. The 3D volume shows organic matter in
green, connected porosity in blue and disconnected porosity in red.
Organic matter and porosity for shale gas samples were
characterized by multi-scale imaging technology. High
resolution FIB-SEM images were utilized to link between
mineralogy, porosity and flow properties.
AT T E N T I O N ! M O R E S A U D I A R A M C O J O U R N A L O F T E C H N O L O G Y
A R T I C L E S AVA I L A B L E O N T H E I N T E R N E T.
Additional articles that were submitted for publication in the Saudi Aramco Journal
of Technology are being made available online. You can read them at this link on
the Saudi Aramco Internet Website: www.saudiaramco.com/jot
The Saudi Aramco Journal of Technology is
published quarterly by the Saudi Arabian Oil
Company, Dhahran, Saudi Arabia, to provide
the company’s scientific and engineering
communities a forum for the exchange of
ideas through the presentation of technical
information aimed at advancing knowledge
in the hydrocarbon industry.
EDITORIAL ADVISORS (CONTINUED)
P R O D U C T I O N C O O R D I N AT I O N
Sami A. Al-Khursani
Richard E. Doughty
Program Director, Technology
Ammar A. Nahwi
DESIGN
Manager, Research and Development Center
Pixel Creative Group, Houston, Texas, U.S.A.
Waleed A. Mulhim
Manager, EXPEC ARC
Complete issues of the Journal in PDF format
are available on the Internet at:
http://www.saudiaramco.com
(click on “publications”).
SUBSCRIPTIONS
Send individual subscription orders, address
changes (see page 85) and related questions to:
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EDITORIAL ADVISORS
CONTRIBUTIONS
Relevant articles are welcome. Submission
guidelines are printed on the last page.
Please address all manuscript and editorial
correspondence to:
EDITOR
William E. Bradshaw
C-86, Wing D, Building 9156
Tel: +966-013-876-0498
E-mail: william.bradshaw.1@aramco.com.sa
Vice President, Southern Area Oil Operations
Ibraheem Assaádan
Unsolicited articles will be returned only
when accompanied by a self-addressed
envelope.
Executive Director, Exploration
President & CEO, Saudi Aramco
Abdullah M. Al-Ghamdi
Nasser A. Al-Nafisee
General Manager, Northern Area Gas Operations
Executive Director, Corporate Affairs
Salahaddin H. Dardeer
Essam Z. Tawfiq
Zuhair A. Al-Hussain
Manager, Jiddah Refinery
ISSN 1319-2388.
Khalid A. Al-Falih
General Manager, Public Affairs
© COPYRIGHT 2014
A R A M C O S E R V I C E S C O M PA N Y
ALL RIGHTS RESERVED
No articles, including art and illustrations, in
the Saudi Aramco Journal of Technology,
except those from copyrighted sources, may
be reproduced or printed without the
written permission of Saudi Aramco. Please
submit requests for permission to reproduce
items to the editor.
gratefully acknowledges the assistance,
contribution and cooperation of numerous
operating organizations throughout the
company.

hisham abass

Transcription

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