adnan kanaan seif

Transcription

adnan kanaan seif

62884araD1R2_ASC027 3/17/13 3:46 PM Page 1
Spring 2013
Saudi Aramco
A quarterly publication of the Saudi Arabian Oil Company
Successful Implementation of Horizontal Multistage Fracturing to Enhance
Gas Production in Heterogeneous and Tight Gas Condensate Reservoirs:
Case Studies
see page 2
Selecting Optimal Fracture Fluids, Breaker System, and Proppant Type for
Successful Hydraulic Fracturing and Enhanced Gas Production – Case Studies
see page 22
Journal of Technology
THE SAUDI ARAMCO JOURNAL OF TECHNOLOGY
62884araD1R2_ASC027 3/17/13 3:46 PM Page 2
On the Cover
Placing a long horizontal wellbore toward the minimum stress
direction plays a major role in the success and effectiveness of
fracturing — to enhance and sustain productivity from tight gas
reservoirs. The Gas Reservoir Management Team has been successfully
exploiting nonassociated gas reservoirs and meeting the Kingdom’s gas
demand by using this process. Pictured here discussing the most
effective drilling and completion plans for nonassociated gas wells
(from left to right) is Ali Habbtar, Adnan Al-Kanaan, Dr. Zillur Rahim
and Dr. Hamoud Al-Anazi from the Gas Reservoir Management
Department.
The Saudi Aramco Journal of Technology is
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A photograph of a reservoir core and thin section and Scanning
Electron Microscope (SEM) photomicrographs of dolomitic and
anhydritic limestone core. The grains appear to have undergone a
minor to moderate amount of compaction as evidenced by the
numerous point and long grain contacts and fewer concavo-convex
grain contacts and stylolites. The dolostone are poorly sorted and the
original fabric of the remaining dolostone has been partially to almost
completely obscured by the dolomitization process. Cementation by
calcite and anhydrite is the main cause of reduction of the primary
pore volume. Later dissolution of grain and dolomitization generated
secondary pores that make up much of the total porosity.
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
Robert M. Arndt, ASC
Program Director, Technology
Ashraf A. Ghazzawi
DESIGN
Manager, Lab Research and Development Center
Pixel Creative Group, Houston, Texas, U.S.A.
Samer S. AlAshgar
Manager, EXPEC ARC
CONTRIBUTIONS
Relevant articles are welcome. Submission
guidelines are printed on the last page.
Please address all manuscript and editorial
correspondence to:
EDITORIAL ADVISORS
Unsolicited articles will be returned only
when accompanied by a self-addressed
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Abdulaziz M. Judaimi
Vice President, Chemicals
Ziyad M. Shiha
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Abdullah M. Al-Ghamdi
General Manager, Northern Area Gas Operations
Salahaddin H. Dardeer
Manager, Riyadh Refinery
ISSN 1319-2388.
EDITOR
William E. Bradshaw
The Saudi Aramco Journal of Technology
Room 2240 East Administration Building
Dhahran 31311, Saudi Arabia
Tel: +966/3-873-5803
E-mail: william.bradshaw.1@aramco.com.sa
Zuhair A. Al-Hussain
Additional articles that were submitted for
publication in the Saudi Aramco Journal of
Technology are being made available online. You
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EDITORIAL ADVISORS (CONTINUED)
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Vice President, Southern Area Oil Operations
AT T E N T I O N ! M O R E S A U D I A R A M C O
JOURNAL OF TECHNOLOGY ARTICLES
AVA I L A B L E O N T H E I N T E R N E T.
Khalid A. Al-Falih
President & CEO, Saudi Aramco
Mohammed Al-Qahtani
Vice President, Saudi Aramco Affairs
Essam Z. Tawfiq
General Manager, Public Affairs
© COPYRIGHT 2013
A R A M C O S E R V I C E S C O M PA N Y
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No articles, including art and illustrations, in
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Spring 2013
Saudi Aramco
A quarterly publication of the Saudi Arabian Oil Company
Contents
Successful Implementation of Horizontal Multistage
Fracturing to Enhance Gas Production in Heterogeneous
and Tight Gas Condensate Reservoirs: Case Studies
2
Dr. Hamoud A. Al-Anazi, Dana M. Abdulbaqi, Ali H. Habbtar and
Adnan A. Al-Kanaan
Evaluation of Nonreactive Aqueous Spacer Fluids for
Oil-based Mud Displacement in Open Hole Horizontal
Wells
10
Peter I. Osode, Msalli Al-Otaibi, Khalid H. Bin Moqbil, Khaled Kilany
and Eddy Azizi
Selecting Optimal Fracture Fluids, Breaker System and
Proppant Type for Successful Hydraulic Fracturing and
Enhanced Gas Production – Case Studies
22
Dr. Zillur Rahim, Dr. Hamoud A. Al-Anazi and Adnan A. Al-Kanaan
Assessment of Multistage Stimulation Technologies as
Deployed in the Tight Gas Fields of Saudi Arabia
30
Mohammed A. Al-Ghazal, Saad M. Al-Driweesh, Fadel A. Al-Ghurairi,
Abdulaziz M. Al-Sagr and Mustafa R. Al-Zaid
An Iterative Solution to Compute Critical Velocity and
Rate Required to Unload Condensate-Rich Saudi Arabian
Gas Fields and Maintain Field Potential and Optimal
Production
39
Hamza Al-Jamaan, Dr. Zillur Rahim, Bandar H. Al-Malki and
Adnan A. Al-Kanaan
Microbial Community Structure in a Seawater Flooding
System in Saudi Arabia
46
Mohammed A. Al-Moniee, Dr. Indranil Chatterjee,
Dr. Gerrit Voordouw, Dr. Peter F. Sanders and Dr. Tony Y. Rizk
Comprehensive Diagnostic and Water Shut-off in Open
and Cased Hole Carbonate Horizontal Wells
52
Nawawi A. Ahmad, Hussein S. Al-Shabebi, Dr. Murat Zeybek and
Shauket Malik
Black Oil, Heavy Oil and Tar in One Oil Column
Understood by Simple Asphaltene Nanoscience
59
Douglas J. Seifert, Dr. Murat Zeybek, Dr. Chengli Dong,
Dr. Julian Y. Zuo and Dr. Oliver C. Mullins
Cementing Abnormally Over-pressurized Formations in
Saudi Arabia
Abdulla F. Al-Dossary and Scott S. Jennings
68
Journal of Technology
THE SAUDI ARAMCO JOURNAL OF TECHNOLOGY
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Successful Implementation of Horizontal
Multistage Fracturing to Enhance Gas
Production in Heterogeneous and Tight Gas
Condensate Reservoirs: Case Studies
Authors: Dr. Hamoud A. Al-Anazi, Dana M. Abdulbaqi, Ali H. Habbtar and Adnan A. Al-Kanaan
ABSTRACT
INTRODUCTION
The heterogeneity and tightness of retrograde carbonate
reservoirs are the main challenges to maintaining gas well
productivities. The degree of heterogeneity changes over the
field and within well drainage areas, where permeability can
decrease from a few millidarcies (md) to less than 0.2 md.
Thorough studies conducted to exploit these tight reservoirs
not only have focused on well performance, but also have been
extended to assure enhancing and sustaining gas productivity
through practical applications of new technologies. The main
objective of this article is to assess the performance of multistage
fracturing (MSF) in horizontal wells that were drilled conventionally and did not meet gas deliverability expectations. This
article provides a detailed analysis of well performances,
exploitation approaches and successful implementation of new
completion technologies, such as horizontal MSF, to revive low
producing gas wells due to reservoir tightness. Placing the horizontal wellbore in reference to the stress directions plays a
major role in the success and effectiveness of fracturing in
enhancing and sustaining productivity.
Several wells had been drilled in tight reservoirs, but could
not achieve or sustain the target gas rate. Recently, two of
these wells were geometrically sidetracked, targeting the development intervals based on logs of the original hole, and
completed with MSF toward the minimum stress direction.
Open hole logs showed a low porosity development similar to
that of the vertical holes; however, after conducting multiple
stages of fracturing, both wells produced a sustainable rate of
more than 25 million standard cubic feet per day (MMscfd),
which prompted connecting them to gas plants. Placing these
sidetracks in the minimum stress direction helped to create
transverse fractures that connected to sweet spots and sustained
gas production. This article provides thorough guidelines for
selecting optimal candidates for MSF, based on reservoir
heterogeneity, and for the proper design and execution of
fracturing. It also addresses various components that contributed
to the success of both wells, such as reservoir development,
workover pre-planning, geomechanical studies, drilling operations and real-time support, completion operations optimization and best practices, and performance evaluation of other
producers in the field.
The increase in energy demand has led operators to exploit all
hydrocarbon resources, including tight gas reservoirs. Accordingly, service companies have developed several technologies
for well completion and stimulation to enable the operators to
target tight gas reservoirs and ensure enhancing and sustaining
gas productivity in the most effective and economical manner.
In Saudi Arabia, most of the conventional gas wells have been
drilled in the maximum horizontal stress direction to avoid any
potential wellbore instability during drilling operations. This
technique has been successfully implemented and has long provided the target sustained gas production from conventional
gas reservoirs1, 2. In the early stage of deploying multistage
fracturing (MSF) in tight reservoirs that were to be acid or
hydraulically fractured, though, it was found in such wells that
the fracture grew along the wellbore in the direction of the
well azimuth and resulted in longitudinal fractures; this caused
the overlapping of two adjacent induced fractures, and thereby
communication between the stages, which meant only two to
three stages of fracture treatments could be performed, while
the remaining stages ended with high rate stimulation. Depending on the length of the wellbore reservoir contact, reservoir
development and stress barriers, more than four fracture treatments in such wells can become redundant or even cause
premature screen-out in proppant fracture treatments3-6.
Wells drilled in the direction of minimum horizontal stress
are potentially more favorable candidates for fracturing from
the perspective of reservoir development and optimal production.
In such situations, hydraulic fractures grow transverse to the
wellbore axis, allowing multiple fractures to be placed without
the possibility of fracture overlapping or communication between
stages. Yet a few wells drilled in the minimum horizontal stress
direction encountered several drilling related problems such as
stuck pipe, hole breakouts causing ovality or formation breakdowns. A comprehensive study is essential to investigate the
feasibility of drilling wells in the minimum horizontal stress
direction to overcome such wellbore instability issues. Correct
mud weight prediction is one key factor during the drilling
stage that helps keep the wellbore stable for the good borehole
geometry needed to run the MSF assembly without complication. Multiple transverse hydraulic fractures can be created in
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SAUDI ARAMCO JOURNAL OF TECHNOLOGY
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a good wellbore geometry to maximize the reservoir contact
area, so as to increase and sustain productivity from the low
quality tight reservoir. The key objectives of the geomechanical
study are to define a safe mud weight program for the horizontal
section of the planned wells by conducting a wellbore stability
study, and to determine a real-time strategy to mitigate and/or
manage wellbore instability problems as they arise. Development of the comprehensive mechanical earth model should allow
optimization in drilling trajectory, running the completion, perforation interval selection and fracture design3, 6, 7.
This article provides thorough guidelines for the selection
of optimal candidates for MSF, based on reservoir heterogeneity,
and for the proper MSF design and job execution. It also addresses various components that contributed to the success of
both wells, such as reservoir development, workover pre-planning, geomechanical studies, drilling operations and real-time
support, completion operations optimization and best practices,
and performance evaluation of other producers in the field.
RESERVOIR DESCRIPTION
The major nonassociated gas reservoirs in a major Saudi Arabian gas field (Field-A) are present in the upper Permian-Late
Triassic formation, which is divided into four depositional cycles.
Three reservoirs (A, B and C) are gas bearing, while ReservoirD is anhydrite. Reservoir-B represents a third order composite
cycle that commenced with a sea level rise following a long
time of exposure and nondeposition at the Permo-Triassic
boundary. Reservoir-B comprises two high frequency sequences,
initiated with the deposition of an open marine thrombolytic
lime mudstone, that shallow upwards into lagoonal and peritidal facies. Reservoir-B is represented by three reservoir facies
composed of oolitic peloidal grainstone, mud-lean oolitic
peloidal packstone and horizontally burrowed shallow subtidal
dolostone. The oolitic peloidal grainstone is the most common,
with moldic porosity in the calcareous upper part of the reservoir. The porosity of the grainstone is enhanced where the rock
is dolomitized to include moldic and inter-crystalline porosity.
The moldic porosity associated with the ooid grainstone represents the main reservoir rock.
The reservoir is highly heterogeneous and exhibits anomalous
fluid and stress characteristics. The formation has limited preserved primary porosity development, with reservoir quality
related to the digenetic process of dolomitization, selective
dissolution of limestone and cementation (anhydrite). Lithological studies show that the reservoir is composed of dolomite
intermingled with limestone and intermittent anhydrite
stringers within the tighter section of the reservoir. The three
types of porosity observed in the reservoir are inter-particle,
inter-crystalline and moldic. Natural fractures have also been
observed in some cores. Therefore, it is fair to say that the
reservoir is structurally complex and heterogeneous. The best
reservoir development is typically noticed in the dolomitized
grainstone with high inter-particle porosity. Reservoir-B in
particular is a large heterogeneous and compartmentalized
reservoir with multiple gas-water contacts, faulting and variation in flow capacity. Regionally, the entire field is divided into
several sections based on reservoir characteristics, porosity development and varying production rates. As such, area specific
development methodologies need to be established to optimize
gas exploitation from each area8.
PETROGRAPHY
Petrographic evaluations of several core samples, Fig. 1, from
various wells indicated a composition of limestone and dolostone: calcite, dolomite and anhydrite are common
cementing/replacement minerals in many samples. Scanning
electron microscope (SEM) and X-ray diffraction (XRD)
analysis conducted on these samples confirmed the observed
mineralogy. The allochems in the lime grainstones are moderately sorted, and average grain size ranges from 330 to 383
microns (medium sand size). Some of the micritic grains have
been replaced by dolomite, Fig. 2. Grains appear to have
undergone a minor to moderate amount of compaction, as
evidenced by the numerous point and long grain contacts and
the fewer concavo-convex grain contacts and stylolites. On the
Fig. 1. Photographs of reservoir cores recovered from pay zone at various depths.
SPRING 2013
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Fig. 2. Thin section and SEM photomicrographs of dolomitic and anhydritic
limestone core.
other hand, the dolostone is poorly sorted, and average grain
size ranges from 438 to 882 microns (upper medium to coarse
sand size). The original fabric of the remaining dolostone has
been partially to almost completely obscured by the dolomitization process. The average crystal size in the dolostone ranges
from 14 to 25 microns (finely crystalline). Cementation by
calcite and anhydrite is the main cause of the reduction of
primary pore volume. Later dissolution of grains and dolomitization generated the secondary pores that make up much of
the total porosity. Porosity and permeability data from conventional core analysis was integrated and cross-plotted by lithology.
The average porosity and permeability in limestone is 12.5%
and 0.196 md, while that in dolostone is 16.6% and 5.88 md.
The low values in limestone are due to the pore-filling calcite
cement that left few primary pores. The secondary pores are
poorly connected due to the extensive
calcite cementation5.
Fig. 3. Porosity development profiles indicate the heterogeneity of Reservoir-B
within the field.
analysis logs and well tests. Therefore, well placement is critical to avoid wet zones and mitigate water encroachments3, 10.
Reservoir heterogeneity necessitates the use of effective
drilling and completion fluids that reduce induced formation
damage if the wells are to achieve their expected potential11, 12.
Pressure compartmentalization has a major impact on production performance due to the potential drop in the bottom-hole
flowing pressure below the dew point pressure, which would
trigger the onset of condensate banking13. Several techniques
have been deployed to address this onset, such as solvent treatment to remove the condensate banking around the wellbore
region, but production has been enhanced only up to several
months14. More effective treatments, such as wettability
alteration, have been extensively tested and approved in the
lab, and are now undergoing field trials on candidate gas
wells15-17.
RESERVOIR HETEROGENEITY
BEST PRACTICES TO EXPLOIT TIGHT GAS RESERVOIRS
Reservoir-B is a naturally fractured gas carbonate reservoir
that covers most of the field. It is the largest in size compared
to the other carbonate and sandstone reservoirs in the field.
The reservoir is part of the carbonate formation and belongs
to the Triassic age. The reservoir quality varies regionally
according to the ratio of anhydrite to carbonate components,
and the matrix porosity and permeability, as illustrated in the
cross section of wells drilled in the field, Fig. 3. The fracture
density increases from the central area, where the fractures are
thin, dispersed and mostly short in length (< 1 ft)9. Therefore,
the reservoir performance varies widely among offset wells in
the same field1, 5.
Analysis of reservoir data indicates the presence of significant areal and vertical pressure compartmentalization. Seismic
data shows variability in reservoir characteristics, which is
usually thin up to 20 ft true vertical depth (TVD). Due to the
thin nature of the reservoir, seismic impedance inversion is not
precise and many times cannot be correlated with log porosity
and reservoir performance. In many places, multiple contaminations of the data make it impossible to arrive at a correct
interpretation. Changing dip and structures also pose major
challenges for correct interpretation. Another challenge is the
presence of multiple gas-water contacts, as observed in formation
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SPRING 2013
Tight gas reservoir development requires good reservoir characterization based on sufficient data from core analysis, offset
well logs, reservoir parameters and production performance.
The following steps are a prerequisite for effective development of a tight gas reservoir:
• Identify the bottom-hole location based on seismic and
offset well data.
• Drill a vertical pilot hole across all layers of the target
reservoir.
• Run open hole logs (density/neutron/resistivity/gamma
ray/caliper).
• Take pressure points and samples to assess fluid
gradients, fluid type and mobility.
• Drill a geometric horizontal hole in the minimum stress
direction targeting the most developed sections observed
in the pilot hole. The geomechanical study parameters
must be determined prior to drilling the sidetrack.
• Maintain the recommended mud weight and inclination.
• Run open hole logs to assess the reservoir development
across the geometric lateral.
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• Design the MSF according to porosity development
packages and ensure there is enough spacing between
stages to avoid communication.
• Place packers across the gauged hole section away from
the washout zones.
• Flow back the well completed with MSFs for cleanup
before conducting the fracturing treatment.
• Drill the geometric horizontal lateral with nondamaging
fluids (no barite) to achieve the needed fracturing fluid
injectivity and avoid the necessity for any wellbore
intervention to open the ports mechanically.
Fig. 4. Schematic of original and sidetracked wellbores of Well-A with porosity
development profiles.
Component
CASE STUDIES
Well-A
Well-A was drilled in 2007 as an open hole Reservoir-C horizontal development well. Due to the poor reservoir quality
seen in the well’s motherbore, it was suspended with a 7”
bridge plug and three cement plugs. In December 2011, plans
were made to sidetrack the well as a horizontal gas producer
across Reservoir-B in the minimum horizontal stress direction
as part of a strategy to exploit that area’s tight gas reservoirs.
The well was sidetracked from inside the 95⁄8” casing using a
mechanical whipstock. After milling the window, an 83⁄8” directional hole section was drilled across Reservoir-A, building
from around a 3° inclination to a 89° inclination at the 7”
liner point inside Reservoir-B, with 103 to 106 pounds per cubic ft (pcf) of potassium chloride (KCl) polymer mud. There
was no major problem in drilling this hole section, with a rate
of penetration (ROP) averaging at 8.3 ft/hr. After running and
cementing the 7” liner, the 57⁄8” section was drilled using a
downhole motor for better ROP (due to continuous rotation
without having to slide for directional control). Potassium (K)
formate mud type was used as it is nondamaging to the reservoir, and its lubricity helped reduce torque and drag while
drilling this hole in the minimum stress direction. A higher
mud weight of 103 pcf mud was chosen, as recommended by
the geomechanical studies, to mitigate wellbore instability issues due to the well azimuth’s being drilled towards the minimum horizontal stress direction. With this mud weight,
Reservoir-B was overbalanced by ~700 psi. Proper sized
CaCO3 chips were added to the K formate mud system to help
create a bridging action across the permeable reservoir sections, thereby minimizing the chance of differential sticking.
Nevertheless, the string got mechanically stuck momentarily
while moving across the reservoir, but it was freed after spotting an acid pill and jarring. While drilling at 15,793 ft measured depth, the downhole motor drive shaft broke, leaving the
bit sub and 57⁄8” bit at the bottom of the well. After running
logs across the open hole section, Fig. 4, the decision was
made to call total depth to avoid risky fishing operations and
to not jeopardize the hole. Therefore, a total of 3,566 ft of
Volume, bbl
15% HCI Spearhead Acid
48
Acid Fracturing Pad
870
28% Emulsified Acid
821
Acid Diverting System-1
197
Acid Diverting System-2
197
Table 1. Fracturing treatment components and volumes for each stage
57⁄8 ” lateral was drilled compared to the 5,400 ft originally
planned. The open hole logs showed development in only two
zones in Reservoir-B with an average porosity of 6%. The well
was completed with two-stage MSF equipment to enhance the
well productivity. Three mechanical packers were installed between the stages to reduce the potential of communication during pumping of the fracturing fluids. The lower frac-port was
opened with a rig on location since it is a pressure actuated port.
The fracturing treatment was designed to create a fracture
in each stage with a gelled pad, after which alternating stages
of acid systems and additional pads were pumped. A polymerfree acid system was used as the diverter system to assist in
maximizing the fracture half-length in each stage. Table 1 lists
the fracturing treatment components and volumes for each
stage. Prior to performing the fracturing, the well was flowed
back for cleanup and achieved a flush rate of 11 MMscfd at
1,723 psi flowing wellhead pressure (FWHP), followed with a
gradual decline. This rate confirmed the intersection of the
wellbore with natural fractures as a result of drilling in the
minimum stress direction18, 19. Both stages were pumped successfully with positive indication of isolation between the two
stages. After conducting the acid fracturing treatments, the
well was flowed back for cleanup at a gas rate of 43 MMscfd
with 2,942 psi FWHP. The productivity index of this well is
shown in Fig. 5, which indicates the effectiveness of the twostage fracturing treatment in enhancing well productivity from
this tight heterogeneous reservoir. Based on these encouraging
results, drilling in the minimum horizontal stress direction and
completion with the MSF assemblies were followed in other
wells designed for the exploitation of the tight gas.
SPRING 2013
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Fig. 5. Productivity index of Well-A after the two-stage fracturing treatment.
Well-B
Well-B was initially drilled and completed in 2004 as a vertical
producer across a deep clastic reservoir; it was permanently
plugged due to poor development and performance after testing. The open hole logs across Reservoir-B showed moderate
development in the B-1 layer. Therefore, a workover was
planned to drill a geometric sidetrack in the B-1 layer in the
minimum horizontal stress direction and to complete it with a
MSF assembly as part of the initiative to exploit Reservoir-B.
The sidetrack operation was carefully planned based on the
lessons learned from Well-A to avoid getting stuck, and drilling
achieved the planned reservoir contact. Due to reservoir heterogeneity, the well encountered 650 ft net reservoir contact in
this Reservoir-B geometric lateral. Three distinct porosity loops
were identified at 440 ft, 160 ft and 50 ft, with the bottom,
middle and upper sections having 5%, 12% and 7% average
porosity, respectively, Fig. 6.
To perform the acid fracturing treatment, initially a 1¾”
coiled tube (CT) was run in hole to clean/displace the wellbore
with 240 bbl of treated water from a depth of 15,568 ft to the
surface. Then two 10 bbl pills of 26% hydrochloric acid were
pumped to try to achieve the minimum injection rate of 5 barrels per minute (bpm) required to displace the balls needed to
activate the ports in the completion. But the maximum injection rate achieved was only 0.6 bpm at 5,800 psi, which
implied that it was not possible to pump the scheduled acid
matrix stimulation treatment in this first stage. Therefore, acid
fracturing of the first stage was canceled due to the poor injectivity caused by either reservoir tightness or plugging of the
frac-port. The activation of the second stage port by pumping
a ball was also not possible at this low rate, so the port had to
be opened mechanically. A 2” CT fitted with a 3” activator
tool was run to open the second stage frac-port at 14,356 ft.
The 2¾” frac-port ball seat was tagged at 14,363 ft, and 4,000
lb of slack-off force was applied on it. To open the port,
treated water was then pumped at 1.3 bpm until the surface
pumping pressure stabilized at 4,900 psi, indicating that the
6
SPRING 2013
port was opened and continuous injection into the formation
was taking place. The CT was then pulled up to 10,000 ft, and
the well was opened to flow over a 90-minute period, during
which it produced gas at a rate of 10 MMscfd at 3,880 psi
FWHP with 75% basic sediments and water. Next, an injectivity
test was performed by pumping 250 bbl of treated water
through the CT and CT/tubing annulus into the formation,
at a stabilized injection rate and pressure of 4 bpm and 6,400
psi, respectively. The rate was deemed adequate to displace
the second stage ball and isolate the first open port, a required
step before proceeding with the scheduled acid fracturing
treatment.
Operations to acid fracture the second and third stages of
the MSF completion system in Reservoir-B were successfully
completed. The second frac-port, set at a depth of 14,494 ft,
was successfully opened by dropping a 3” ball. A mini fall-off
(MFO) was performed at a maximum pumping rate, treating
pressure and bottom-hole pressure (BHP) of 20 bpm, 9,900 psi
and 13,800 psi, respectively, followed by a step rate test (SRT)
at a maximum rate, treating pressure and BHP of 25 bpm,
11,000 psi and 14,400 psi, respectively. Then the second stage
main fracturing treatment was performed by displacing a total
volume of 2,094 bbl at a maximum rate, treating pressure and
BHP of 60 bpm, 11,600 psi and 13,200 psi, respectively, into
the formation. The third frac-port, set at a depth of 13,312 ft,
was successfully opened by dropping a 3¼” ball. The MFO
was performed by displacing a total volume of 50 bbl of
Fig. 6. Schematic of original and sidetracked wellbores of Well-B with porosity
development profiles.
Fig. 7. Productivity index of Well-B after the two-stage fracturing treatment.
62884araD2R1_ASC026 3/15/13 11:23 PM Page 7
treated water at a maximum rate, treating pressure and BHP of
15 bpm, 8,400 psi and 12,700 psi, respectively, followed by a
SRT at a maximum pumping rate, treating pressure and BHP
of 20 bpm, 10,000 psi and 14,000 psi, respectively. Then the
third stage main fracturing treatment was successfully performed by displacing a total volume of 1,020 bbl at a maximum rate, treating pressure and BHP of 59 bpm, 11,880 psi
and 13,900 psi, respectively, into the formation. The well was
flowed back for cleanup. The productivity index profile is
shown in Fig. 7. The gas rate reached 36 MMscfd at 2,560 psi
FWHP. The successful implementation of sidetracking and
fracturing converted Well-B from a suspended well drilled in
2004 into a strong producer that will be connected to the nearest
nonassociated gas plant.
CONCLUSIONS AND RECOMMENDATIONS
The strategy of drilling a pilot hole to help in placing the horizontal hole to target the best porosity development in a heterogeneous reservoir was very practical. Placing these sidetracks
in the minimum stress direction and using MSF completions
helped to create transverse fractures that connected to sweet
spots and sustained gas production. The sidetracks also
opened the possibility to intersect with the natural fractures
that exist parallel to the maximum stress direction. Geomechanical studies helped control wellbore instability by predicting the proper mud weight needed to drill the horizontal
lateral in the minimum stress direction. The application of the
MSF completion proved successful in enhancing gas productivity from these tight reservoirs.
Based on these case studies, it is recommended to consider
the following in the exploitation of tight gas reservoirs:
• Drilling horizontal wells in the minimum stress direction
is a prerequisite for successful MSF in tight gas reservoir
development.
• Geomechanical studies are essential to ensure problemfree drilling and placing of the horizontal wellbore in
the direction of the minimum stress.
• Mud weight windows for hole breakouts and loss of
circulation need to be predicted from the geomechanical
study as a function of well deviation and azimuth.
• A real-time geomechanical model has proven to be
effective in predicting the proper mud weight window
and preventing wellbore instability and drilling related
problems.
• Sufficient spacing between frac-ports in the MSF
completion plays a major role in achieving desired
fracturing pressure and eliminating communication
through packers, which must be placed across the
gauged hole section away from the washout zones.
• Wells completed with MSF need to be flowed back for
cleanup before conducting the fracturing treatment.
ACKNOWLEDGMENTS
The authors would like to thank Saudi Aramco management
for the permission to present and publish this article. We
appreciate the help of all personnel from the Gas Reservoir
Management and Gas Production Engineering Departments
for their assistance.
This article was presented at the Abu Dhabi International
Petroleum Exhibition and Conference (ADIPEC), Abu Dhabi,
U.A.E., November 11-14, 2012.
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and Al-Faifi, M.G.: “Impact of Completion Fluids on
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Ahmed, M.S., Al-Faifi, M.G., et al.: “Gas Productivity
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SPRING 2013
Production Wells,” SPE paper 117353, presented at the
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2010.
BIOGRAPHIES
Dr. Hamoud A. Al-Anazi is the
General Supervisor of the North
Ghawar Gas Reservoir Management
Division in the Gas Reservoir
Management Department (GRMD).
He oversees all work related to the
development and management of huge
gas fields like Ain-Dar, Shedgum and ‘Uthmaniyah.
Hamoud also heads the technical committee that is
responsible for all new technology assessments and
approvals for GRMD. He joined Saudi Aramco in 1994 as
a Research Scientist in the Research & Development Center
and moved to the Exploration and Petroleum Engineering
Center – Advanced Research Center (EXPEC ARC) in
2006. After completing a one-year assignment with the
Southern Area Reservoir Management Department,
Hamoud joined the Gas Reservoir Management Division
and was assigned to supervise the SDGM/UTMN Unit and
more recently the HWYH Unit. With his team he
successfully implemented the deepening strategy of key
wells that resulted in a new discovery of the Unayzah
reservoir in UTMN field and the addition of Jauf reserves
in the HWYH gas field.
Hamoud’s areas of interests include studies of formation
damage, stimulation and fracturing, fluid flow in porous
media and gas condensate reservoirs. He has published
more than 50 technical papers at local/international
conferences and in refereed journals. Hamoud is an active
member of the Society of Petroleum Engineers (SPE) where
he serves on several committees for SPE technical
conferences. He is also teaching courses at King Fahd
University of Petroleum and Minerals (KFUPM), Dhahran,
Saudi Arabia, as part of the Part-Time Teaching Program.
62884araD2R1_ASC026 3/15/13 11:23 PM Page 9
In 1994, Hamoud received his B.S. degree in Chemical
Engineering from KFUPM, and in 1999 and 2003,
respectively, he received his M.S. and Ph.D. degrees in
Petroleum Engineering, both from the University of Texas
at Austin, Austin, TX.
Dana M. Abdulbaqi has been a
Petroleum Engineer with Saudi
Aramco since 2004. She has had
several assignments with various
petroleum engineering and
development departments, including
the Production and Facilities
Development Department and Reservoir Management
Department.
Dana is an active member of the Society of Petroleum
Engineers (SPE) from which she obtained her Petroleum
Engineering Certification. She is also a member of the
International Association for Energy Economics as well as
the Saudi Council of Engineers. In addition to her
involvement in these professional societies, in 2012, she
established and chaired Qudwa (www.qudwa.org), which is
an affinity group that aspires to encourage dialogue and
open discussion by providing opportunities for its members
to interact via networking, skill building, and knowledge
sharing and mentoring with special consideration to gender
differences.
Dana received her B.S. degree in Architecture from
Virginia Tech, Blacksburg, VA. She completed an M.S.
degree in Petroleum Engineering from Texas A&M
University, College Station, TX, and is currently pursuing a
Ph.D. degree in Mineral and Energy Economics at the
Colorado School of Mines, Golden, CO.
Ali H. Habbtar is a Supervisor of the
HWYH Unit in the Gas Reservoir
Management Department and is
responsible for the management of all
reservoirs feeding the Hawiyah Gas
Plant. He has over 10 years of industry
experience in reservoir engineering and
well productivity enhancement through stimulation.
As a member of the Society of Petroleum Engineers (SPE),
Ali has published numerous SPE papers. He is the chairman
of the upcoming 2013 SPE Saudi Arabia Technical
Symposium.
Ali received his B.S. degree in Petroleum Engineering
from Pennsylvania State University, University Park, PA,
and an M.B.A. from the Instituto de Estudios Superiores de
la Empresa (IESE Business School), Barcelona, Spain.
Adnan A. Al-Kanaan is the Manager
of the Gas Reservoir Management
Department (GRMD) where he
oversees three gas reservoir management divisions. Reporting to the Chief
Petroleum Engineer, Adnan is directly
responsible for making strategic
decisions to enhance and sustain gas delivery to the
Kingdom to meet its ever increasing energy demand. He
oversees the operating and business plans of GRMD, new
technologies and initiatives, unconventional gas development programs, and the overall work, planning and
decisions made by his more than 70 engineers and
technologists.
Adnan has 15 years of diversified experience in oil and
gas reservoir management, full field development, reserves
assessment, production engineering, mentoring young
professionals and effectively managing large groups of
professionals. He is a key player in promoting and guiding
the Kingdom’s unconventional gas program. Adnan also
initiated and oversees the Tight Gas Technical Team to
assess and produce the Kingdom’s vast and challenging
tight gas reserves in the most economical way.
Prior to the inception of GRMD, he was the General
Supervisor for the Gas Reservoir Management Division
under the Southern Reservoir Management Department for
3 years, heading one of the most challenging programs in
optimizing and managing nonassociated gas fields in Saudi
Aramco.
Adnan started his career at the Saudi Shell Petrochemical Company as a Senior Process Engineer. He then
joined Saudi Aramco in 1997 and was an integral part of
the technical team responsible for the on-time initiation of
the two major Hawiyah and Haradh Gas Plants that
currently process more than 6 billion cubic feet (bcf) of gas
per day. Adnan also directly managed the Karan and Wasit
fields — two major offshore gas increment projects — with
an expected total production capacity of 4.3 bcf of gas per
day.
He actively participates in the Society of Petroleum
Engineers’ (SPE) forums and conferences and has been the
keynote speaker and panelist for many such programs.
Adnan’s areas of interest include reservoir engineering, well
test analysis, simulation modeling, reservoir characterization, hydraulic fracturing, reservoir development
planning and reservoir management.
He will be chairing the 2013 International Petroleum
Technical Conference to be held in Beijing, China.
Adnan received his B.S. degree in Chemical Engineering
from King Fahd University of Petroleum and Minerals
(KFUPM), Dhahran, Saudi Arabia.
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Evaluation of Nonreactive Aqueous Spacer
Fluids for Oil-based Mud Displacement in
Open Hole Horizontal Wells
Authors: Peter I. Osode, Msalli Al-Otaibi, Khalid H. Bin Moqbil, Khaled A. Kilany and Eddy Azizi
ABSTRACT
Reactive mud cake breaker fluids in long open hole horizontal
wells located across high permeability sandstone reservoirs
have had limited success because they often induce massive
fluid losses. The fluid losses are controlled with special pills,
polymers and brine or water, causing well impairment that is
difficult to remove when oil-based mud (OBM) drill-in fluids
(DIFs) are used. This situation has resulted in a drive for an
alternative cleanup fluid system that is focused on preventing
excessive fluid leak off, maximizing the OBM displacement
efficiency and allowing partial dispersion of the mud cake for
ease of its removal during initial well production. The twostage spacer cleanup fluid is composed of a nonreactive fluid
system, which includes a viscous pill with nonionic surfactants,
a gel pill, a completion brine and a solvent.
Extensive laboratory testing was conducted at simulated
reservoir conditions to evaluate the effectiveness of the OBM
displacement fluid system. The study included dynamic highpressure/high temperature (HP/HT) filter press tests and coreflood tests, in addition to wettability alteration, interfacial
tension and fluid compatibility tests.
The spacer fluid parameters were optimized based on wellbore fluid hydraulic simulation and laboratory test results,
which indicated minimal fluid leak off and a low risk of emulsion formation damage. Three well trials then were conducted
in a sandstone reservoir drilled with OBM in a major offshore
field. All three trial wells (one single lateral and two dual laterals) treated with the displacement fluid system have demonstrated improvement in production performance. This article
will discuss in detail the spacer fluids’ optimization process,
the laboratory work conducted and the successful field treatments performed.
immediately after well completion to avoid long-term mud and
solids aggregation in the wellbore. Residual mud cakes after
wellbore displacement with solids-free OBM DIFs are relatively thinner and easier to remove at low drawdown pressures
during the initial production phase1, 2. Nevertheless, in many
other conditions, wellbore cleanup with reactive treatment
fluids is required for filter cake dissolution and removal.
An effective cleanup treatment delivers optimum life cycle
productivity by allowing access to the entire pay zone at a minimum drawdown pressure across the reservoir, and therefore,
lowers the risk of early water breakthrough and fines migration3.
Uniform placement of conventional breaker fluids for complete
treatment of the horizontal wellbore, however, is difficult to
achieve, especially in high permeability sandstone reservoirs,
because of rapid fluid reaction and leak off at the first point of
contact. Alternative systems, such as delayed reaction breaker
(DRB) fluids, have provided only limited respite due to the
rapid cake solubility associated with complete hydrolysis of
esters for in-situ generated organic acid at high bottom-hole
temperatures4. Other DRB fluids with ethylene diamine tetraacetic acid (EDTA) or its derivatives have indicated risks of
reprecipitation when used in a divalent salt environment, while
the inclusion of hydroxyl ethyl cellulose as a delay mechanism
in DRB fluids shields calcium carbonate (CaCO3) particles
from the reactive fluid component and reduces the productivity
performance5. Dual-purpose delayed cleanup fluids that are
based on reversible invert emulsion DIF systems are complicated
and rely on a delicate pH control to be effective6, 7. Current
DRB fluids are also deemed suboptimal for cleanup in extended
reach horizontal or multilateral wells when a noneffective
mechanical isolation device is utilized with a wash pipe in the
completion bore8.
Nonreactive Cleanup Fluids
INTRODUCTION
Oil-based mud (OBM) drill-in fluids (DIFs) are favored for
drilling extended horizontal wells located in reservoirs with
water sensitive shale sections since they provide superior inhibition, greater lubricity, reduced mechanical friction and
improved wellbore stability relative to water-based mud
(WBM) DIFs. Ideally, removal of OBM cake should be done
10
SPRING 2013
The ideal cleanup solution for a high risk, high permeability/
fractured reservoir is an extended delay breaker fluid system
that is benign at the surface but provides homogeneous treatment of OBM DIF mud cake without causing severe wellbore
fluid losses during completion. The absence of such an ideal
fluid has prompted the use of nonreactive aqueous fluids with
a properly designed displacement process to facilitate wellbore
62884araD3R1_ASC026 3/15/13 11:25 PM Page 2
OBM clean out and create a uniform mud cake “pinhole”
prior to gradual liftoff of the residual cake during an early
flow back/production kickoff operation9, 10. This technique is
supported by previous formation damage studies, which indicate that DIF design optimization for filter cake removal via
drawdown can deliver up to 95% inflow performance for gas
and oil reservoirs with minimum permeabilities of 1-2 mD and
0.5-1 D, respectively11.
OBM DIFs generally utilize CaCO3 solids as a density and
bridging material. OBM filter cake and solids removal in open
hole/sand screen completion wells demands the use of cleanup
fluids that can disperse the oily particles and thereby enhance
the residual DIF solids clean out from the wellbore. The potential success of nonreactive fluids in achieving wellbore clean
out is predicated on the premise that only a limited filter cake
removal, albeit uniformly across the wellbore, is required for
optimum well production performance. One well productivity
assessment model estimates that less than 5% filter cake removal is required in a high permeability sandstone reservoir
with a slotted liner completion12-14. The solids-free, postcleanup displacement brine fluids will also reduce the risk of
damage in wells that are suspended with low solids, oil-based
DIFs/completion fluids in the wellbore long before the well is
cleaned up and brought onstream.
Nonaqueous treatment fluids will not produce the desired
wettability changes in the near-wellbore area, whereas conventional aqueous surfactant cleanup fluids may cause damage,
which will hamper oil production if an emulsion block forms
in the wellbore due to water saturation15-17. With the advent of
microemulsion technology, nonreactive aqueous treatment fluids can be customized to achieve a relatively more effective
well cleanup. Microemulsions are thermodynamically stabilized
multicomponent fluids composed of oil, water and surfactant
blends, which solubilize the oil component of the OBM with
limited mechanical agitation18-24. Since acid-free micro-emulsion fluids are incapable of dissolving OBM solid particles, it is
critical that dispersed residual filter cake solids are able to flow
through the sand screen completion apertures when used in
stand-alone screen completions. Additionally, the mechanical
aspect of the displacement process must be optimal for maximum removal of fluid solids in the wellbore, with final brine
returns having a solids/sediments content < 1% or fluid clarity
below 300 nephelometric turbidity units (NTUs)25.
Reservoir OBM DIFs and Spacer Fluids Design Options
The predominant development oil reservoir in the field selected
for the cleanup fluid trials is relatively heterogeneous with a
wide variation of permeability (0.25 to 6 D) across the target
pay zone section, located at a shallow total vertical subsea
depth of <5,500 ft. The reservoir is a thick sequence of unconsolidated sandstone with siltstone, shale and limestone interbeds. Formation fluid is composed of medium light crude
and relatively saline formation water with a maximum bottom-hole static temperature (BHST) of ~160 °F. The well laterals were drilled with a relatively low density, invert emulsion
OBM (75 pcf to 80 pcf, 70/30 oil/water ratio (OWR)) and
completed as open hole horizontal wells with 5½” inflow control devices (ICDs)/sand screens and production equalizers installed in the 8½” lateral section (4½” ICDs/sand screens and
production equalizers were used in the 61⁄8” laterals for
slim/sidetracked wells). The CaCO3 loading required to
achieve the desired mud weight was approximately 120 lb/bbl,
Table 1. Previous laboratory investigation of field muds for
Additive
Unit
Conc.
Property
Unit
Value
Mineral Oil
bbl
0.52
Density
lb/ft3
~75
Emulsifier
gal
1.5
Plastic Viscosity
cp
18-20
Lime
lb
6.0
Yield Point
lb/100 ft2
20-25
Filtration Control
lb
6.0-8.0
10 sec. Gel
lb/100 ft2
4-6
bbl
0.22
10 min. Gel
lb/100 ft2
8-12
Organophilic Clay/Viscosifier
lb
6.0-8.0
Filtrate, HP/HT
ml/30 min
1-2
Organic Surfactant
gal
0.5
Electric Stability
volts
>800
CaCl2 (78%)
lb
41
Chlorides
mg/l
±350,000
CaCO3 (fine)
lb
90
Excess Lime
lb/bbl
4-6
CaCO3 (medium)
lb
30.0
Oil/Water Ratio
Water
70/30
Table 1. Composition and properties of OBM DIF
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62884araD3R1_ASC026 3/15/13 11:25 PM Page 3
their role in DIF induced formation damage had detected permeability reductions of 25% to 65% after mud exposure to
core samples, with higher alterations recorded for higher permeability cores. Improvements observed after physical mud
cake removal and core spinning down suggested that mud cake
was the primary barrier to flow, while higher density (~90 pcf)
muds caused additional alteration in permeability26.
Following traditional practice, the newly drilled wells were
circulated using a solids-free version of the same OBM formulated with a higher density base brine (~90 ppb CaCl2) to facilitate the installation of the sand screen/completion liner
assembly on the bottom. Some of the wells were subsequently
left untreated for weeks and brought onstream only after production hookup facilities were installed. With the rig on-site,
other wells were treated with breaker fluids, which resulted in
severe losses and difficult well control situations. When there is
a high risk of severe losses with breaker fluids, nonreactive
aqueous spacer fluids are recommended to displace the DIFs
from the well. A combination of chemical and mechanical
actions by the spacer fluid system is required to achieve minimum damage in extended horizontal wells during cleanup27, 28.
Criteria that effective spacer fluids must achieve in a waterbased spacer and completion formulation are:
fluid displacement behavior at expected downhole conditions
and determine optimum cleanup fluid performance. The software applied the well geometry, fluids density and rheology
data to generate different fluids flow/interface profiles at specific pump rates. Previous industry experience had identified
the need for contrasts between the mechanical properties of the
fluid being displaced and those of the displacement fluid to
enhance the wellbore fluid’s clean out29, 30.
A base case model was developed using a spacer fluid system, i.e., a base oil, a weighted/viscous spacer (push pill) and a
low weight cleaning/wash pill, which was a blend of brine and
surfactants, Figs. 1a and 1b. Two sets of simulations were conducted to optimize the spacer train design parameters, such as
density, rheology, fluid volume and contact times. This was
required to determine which spacer train displacement process
demonstrated the most displacement efficiency. The two sets of
simulations also tested the sensitivity of the wellbore fluid displacement performance to the physical properties (density and
rheology) of the key spacer (push pill) and the volume/contact
time of the component spacers. Table 3 describes the varied
parameters for the different case scenarios.
The simulation results reflected displacement performance
• Effective displacement of the OBM.
(76 pcf Weighted/Viscous Surfactant Spacer):
• No excessive losses during different displacement stages.
Mix Water + 22 ppb Viscosifier Additive
+ 88 ppb Barite + 2.75 gals/bbl Surfactant
Additive + 0.36 gal/bbl Co-Surfactant
Additive + Defoamer
• Thinning and weakening of the mud cake by solubilization of the oil from the OBM and filter cake into the
spacer fluid, and wettability reversal (to water-wet) for
better mud cake dispersion and easier lift-off during
production.
Spacer-1
The aqueous spacer fluids train options considered included:
Spacer-2
Mix Water + 0.04 ppb Specialty Additive
+ 0.8 gal/bbl Gel Additive + Defoamer (as
needed)
Spacer-3
(75 pcf Brine Spacer)
(75 pcf Gel Spacer):
• Dispersant base oil, viscous push/gel pill, wash/
surfactant pill (3-spacer fluids train).
• Viscous push pill, viscous push/gel pill, brine spacer,
surfactant/solvent wash pill (4-spacer fluids train).
• Dispersant base oil, viscous push/gel pill, brine spacer,
wash/surfactant pill, solvent pill (5-spacer fluids train).
Following a decision to test an acid-free microemulsion
spacer fluid (MSF) system, the 4-spacer fluids train system containing a surfactant/solvent wash pill was selected. The composition and properties of the spacer train are given in Table 2.
The proposed nonionic surfactants used in the above spacer
system were reported to be insensitive to temperature and
salinity.
(62 pcf Solvent/Brine Wash Fluid):
Spacer-4
Mix 75 pcf Brine + 40% by vol. Solvent
Additive
Table 2. Spacer fluids formulation
Simulation Case
(Viscous Push Pill)
Density
Rheology (PV/YP)
90 pcf
25 cp/60 lb/100 ft2
Case-1
90 pcf
42 cp/96 lb/100 ft2
Case-2
80 pcf
34 cp/52 lb/100 ft2
Base Case
Fluids Hydraulics and Spacer Displacement Modeling
Wellbore fluids displacement efficiency is essentially determined by the hydrodynamic properties of the OBM and the
cleanup fluids, in addition to the chemical interaction of the
DIFs, completion fluids and formation fluids. Wellbore fluid
hydraulics analysis software was used to evaluate the fluid12
SPRING 2013
Sensitivity Cases
Table 3. Fluids displacement simulation variables
62884araD3R1_ASC026 3/15/13 11:25 PM Page 4
Fig. 1a. Base case flow profile (push pill displacement).
Fig. 2a. Sensitivity Case-2 flow profile (Push pill displacement).
for each scenario in terms of “fluid concentrations” and “risk
of mud left on the wall” snapshots. The absence of visible
improvement with higher rheology spacers (Sensitivity Case 1)
and the significantly poorer mud removal observed at lower
density (r = 80 pcf) (Sensitivity Case 2) indicated that the density difference is a more dominant factor than the rheology difference, Figs. 2a and 2b. The second set of simulation results
also showed that increasing the volume of the high density
push pill relative to that of the wash/cleaning pill gave improvement in the cleanup. It was noted that the key spacer
fluid/push pill was unable to remove bulk mud from the narrow side of the open hole section in all cases at a poor pipe
standoff of ǉ50%. These simulation results were instrumental
in altering the push pill density to 90 pcf, which led to improved performance in subsequent spacer fluid applications.
EXPERIMENTAL STUDIES
Fig. 1b. Base case flow profile (wash pill displacement).
Fig. 2b. Sensitivity Case-2 flow profile (Wash pill displacement).
Fig. 3. OBM DIF filtrate vs. square root of time.
OBM/
Spacer Fluid
RPM Readings
PV cp
YP
lb/100
ft2
HP/HT Filter Press and Rheology Tests
A fluid loss performance test carried out with a HP/HT filter
press on the field OBM DIFs indicated a minimal fluid loss at
static conditions with a 35-micron ceramic disc at 140 °F (total filtrate volume ~5.0 ml after 60 minutes), Fig. 3. Table 4
shows the rheology for the laboratory OBM, field OBM and
key spacers, with the field mud showing higher rheological values
due to the additional solids accumulated during the drilling
600
300
200
100
Field OBM
119
74
55
32
45
29
Lab OBM
97
60
52
30
37
23
Push Pill
114
78
63
48
36
42
Gel Pill
73
58
51
43
15
43
Table 4. OBM and spacer fluids rheology
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62884araD3R1_ASC026 3/15/13 11:25 PM Page 5
Photos 1a and 1b: OBM DIF sample before and after surfactants at 120 °F.
Fig. 4. Surfactant effect on OBM electrical stability.
Photos 2a and 2b: Compatibility test of solvent pill with OBM base oil at 120 °F
and 1,000 psi.
microemulsion surfactant wash fluid reduced the OBM rheology by 30% to 60%. Measurement of the rheology of the
OBM and spacer fluid mixtures was required to determine the
fluid’s behavior at the mixing zone/interface during wellbore
displacements. The test also enabled performance comparison
of different surfactants or surfactant concentrations on specific
OBM DIFs.
Fig. 5. Conventional/Microemulsion surfactant effect on OBM rheology.
process. The push pill designed in this work showed a favorable yield point (YP) in contrast with the conditioned DIF
(similar to the lab DIF) and field OBM before commencement
of the cleanup operation. The YP value of the key displacing
fluid (push pill) was approximately 1.5 times the YP for the
displaced OBM (laboratory and field), as recommended by
Javora and Adkins30.
The dispersion effect of the surfactant/solvent wash pill on
the OBM was evaluated by measuring the change in the emulsion stability and rheology of the OBM when it was mixed
with different volumes of the wash pill. This change in emulsion stability and rheology was measured using an electrical
stability meter and a viscometer, respectively. Figure 4 shows
the increased reduction in electrical stability achieved by increasing the mixing ratio of the surfactant spacer with the
OBM. At around 12 wt% of wash pill added to the OBM, a
reduction of 90% in emulsion stability was measured. This reduction is an indication of how well the wash pill was dispersing the OBM and reversing the wettability to more water-wet.
A complete dispersion of the mud components in the wash pill
was accomplished at a concentration of 20 wt%.
Figure 5 shows the change in viscometer reading that was
caused by the addition of 10% vol/vol of the wash pill to the
OBM at speeds ranging from 100 rpm to 600 rpm. The
14
SPRING 2013
Compatibility/Wettability and Interfacial Tension Tests
A bottle test was performed to confirm the ability of the surfactant/wash pill to water-wet the OBM particles. Tests that
simulated the OBM/surfactant solution interaction were prepared with an OBM/solution ratio of 10/90 that was left to
soak overnight at ~120 °F. Visual observation of solid particle
dispersion, with none of the particles sticking on the glass,
gave an indication of the cleaning effectiveness. Mud particles
were fully dispersed and water wetted for the mixed solution,
Photos 1a and 1b. See-through cell tests were also carried out
to assess the compatibility of the solvent additive with the
OBM DIF base oil by observing the mixed fluids at different
ratios of 25/75, 50/50 and 75/25, Photos 2a and 2b. Similar
compatibility tests were carried out between the solvent and
the base brine, Photos 3a and 3b. No precipitation or emulsion
droplets were observed for the different fluids at bottom-hole
conditions, i.e., a circulating pressure of 1,000 psi and a temperature of 120 °F. A Winsor Type III middle-phase microemulsion was also confirmed after mixing the OBM with a
surfactant/solvent wash pill, Photo 4.
An inter-facial tension (IFT) test was conducted on the surfactant based wash pill/OBM fluid system, using the spinning
drop method for measuring ultra-low IFTs to determine the effectiveness of the surfactant solutions in solubilizing the oil in
the aqueous surfactant based solution and in water wetting the
62884araD3R1_ASC026 3/15/13 11:25 PM Page 6
Fluid Interface
IFT Measurement
Water: OBM
48
Solvent/Wash Pill-A: OBM
0.160
Solvent/Wash Pill-B: OBM
0.078
Table 5. Results of IFT tests at 70 °C
Photos 3a and 3b: Compatibility test of solvent pill with 67 pcf NaCl completion
brine at 120 °F and 1,000 psi.
Photos 5a and 5b. OBM sample mud cake and after cleanup flush with solvent
spacer at 120 °F.
Photo 4. Confirmation of Winsor Type III microemulsion using surfactant
solution with field OBM sample.
OBM filter cake. This test followed from the established fact
that cleaning of oil and oily dirt from solid surfaces with surfactant solutions is largely dependent on ultra-low IFTs (<< 1
µN/m = 1 dyne/cm) between the immiscible fluids. Table 5
shows two different surfactant/solvent solutions that gave relatively low IFTs with the OBM at 70 °C (158 °F), i.e., 0.160
and 0.078 dynes/cm as against the ~48 dynes/cm expected for
a typical water/oil fluid interface. Also, the surfactant/solvent
solution was completely haze-free, indicating salinity tolerance
at the test temperatures.
Performance of Cleanup Flush/Circulation Treatment
To study the ability of the spacer train to thin and weaken the
filter cake while maintaining minimum fluid losses during the
wellbore clean out, a filter press test was conducted on the
cleanup spacers using a synthetic ceramic disc of the permeability range, 35.0 µm, (equivalent to 10 Darcies) and OBM
DIFs at expected reservoir conditions. OBM filter cake was
prepared by circulating the mud for 30 minutes at an expected
overpressure of 500 psi and a bottom-hole circulating temperature of 140 °F, followed by 3 hours of static conditions. The
spacer fluids were circulated sequentially, one after the other,
on top of the filter cake, with dynamic conditions at 350 psi
and 140 °F. Filtrate volume was monitored during the circulation of each spacer, and the total fluid leak off (TFL) after the
circulation treatment was recorded. The thickness and weight
of the mud cake were also recorded before and after the
cleanup flush treatment, and the percent filter cake reduction
(FCR) was computed.
It was observed that the solvent wash pill altered the wettability of the mud cake and OBM particles, changing from oilwet to water-wet after circulation treatment. Also, it was
shown that the wash pill thinned the mud cake and reduced its
weight, Photos 5a and 5b. The results showed a maximum
TFL < 30 ml (~20% of treatment fluid) and a FCR of ~10% to
20% with optimized spacer fluid formulations after repeated
tests at expected operating conditions, Table 6.
Coreflood Tests
Coreflood tests were conducted to determine the return permeability using different spacer trains in a dynamic fluid loss instrument with two test cells. The tests were conducted at a
third-party laboratory facility using these procedures:
• Base Permeability Measurement: Cores were loaded into
the test cells, and the flow of mineral oil was initiated in
the production direction to obtain initial core
permeability at 150 °F.
• Dynamic Fluid Loss Measurement: Mud was loaded
into the system, and the pump was started at a
predetermined shear rate that matched the wellbore
flow conditions. Differential pressure across the cores
was 350 psi while system temperature was maintained
at 150 °F, with fluid loss lines opened for 4 hours.
• Static Fluid Loss Measurement (pump shutdown): The
mud differential pressure across the core was reduced to
SPRING 2013
15
62884araD3R1_ASC026 3/15/13 11:25 PM Page 7
W 1, g
W2, g
W3, g
FCR%
Ti, mm
Tf, mm
Reduced Cake
Thickness, %
Solvent Pill
45.99*
56.36
54.451
18.41
9.57
8.89
7.11
Surfactant
52.581
57.97
57.491
8.89
9.28
9.04
2.56
Cleanup Flushes
53.743
62.281
60.520
20.63
10.03
9.38
6.48
Spacer
*10 micron ceramic disk
Table 6. Results of the filter press tests
pared to an offset well that had experienced severe fluid losses
during breaker fluid treatments at a similar well completion
stage, with those losses controlled using killing fluid, Table 8.
Test Well-2
Fig. 6. Retained permeability vs. pore volume of cleanup treatment fluid.
250 psi while the system temperature was increased to
150 °F, with fluid loss lines opened for 2 hours.
• Cleanup Flush/Circulation Treatment: Two different
cleanup spacer fluids trains were circulated with the
differential pressure across the two cores maintained at
350 psi.
• Final Permeability Measurement: Mineral oil was again
initiated in the production direction at the same bottomhole conditions used for the base permeability
measurement above.
The proportional retained permeability computed for the
two spacer fluids trains enabled the selection of the superior
surfactant/solvent wash formulation with acceptable retained
permeability (> 70%), Fig. 6. The selected spacer train was
composed of nonreactive components, i.e., nonionic surfactant, gel pill, sodium chloride (NaCl) completion brine and
solvent pill.
FIELD APPLICATION AND CASE HISTORIES
Test Well-1
The well was originally drilled and completed as a deviated
cased hole/perforated completion across the target reservoir (7”
casing was cemented from total depth to the surface) in 1984.
The well was subsequently sidetracked using a 75 pcf diesel
oil-based DIF and thereafter completed with a 4½” sand screen
and ICDs on the bottom after sidetracking and cementing a
4½” casing off the bottom inside a 7” open hole in July 2009.
The two-stage cleanup wash with a 4-spacer fluids train was
carried out as planned in August 2009, Table 7. The post-completion production test indicated a production increase of 10%
(5% water cut) compared to offset wells in the area. Well performance was better, with a 60% higher production rate com16
SPRING 2013
The dual horizontal well was drilled with 75 pcf to 80 pcf mineral oil-based DIFs and completed with a 5½” ICD/sand
screen in the lower lateral and a 4½” ICD/sand screen in the
upper lateral in July 2009. The 3,440 ft lower lateral was
treated with 200 bbl of a reactive microemulsion/mesophase
fluid system due to the unavailability of the spacer fluid additives. The treatment fluid was formulated with NaCl brine/
10% acetic acid and nonionic surfactant additive (displaced
and spotted in open hole with 125 bbl of 70 pcf NaCl brine).
The 3,300 ft upper lateral cleanup was carried out using
acid-free MSFs in two stages with NaCl brine as the displacement fluid in July 2009, Table 7. The initial displacement rate
was limited at <1.2 bpm with maximum pressure at 700 psi
during treatment of the upper lateral to avoid premature
packer setting. The post-completion production test indicated
a 157% (0% water cut) production rate when compared with
the offset well. Well performance was better than that of the
offset wells that had encountered severe fluid losses while being treated with breaker fluids during completion, Table 8.
Test Well-3
The last test well had a hole configuration and completion
design similar to that of test Well-2, but both laterals were
cleaned out with the microemulsion fluid system in August
2009. A two-stage cleanup wash with a 4-spacer fluids system
was carried out prior to completion brine displacement and
circulation in both laterals. For the 61⁄8” upper lateral (~2,540
ft), initial displacement was maintained at <1 bpm with maximum pressure at 800 psi to avoid premature packer setting.
Similarly, the initial displacement was kept below 5 bpm for
the lower lateral (~3,180 ft), Fig. 7.
Brine samples were collected on the surface after the firststage and second-stage cleanup followed by displacement brine
to assess the performance of the well cleanup operation. Extensive analysis of the brine returns after more than 200% hole
volume displacement indicated adequate removal of the solids
or sediments contained in the wellbore (less than 0.3% solids
62884araD3R1_ASC026 3/15/13 11:25 PM Page 8
Test Well-1
Test Well-2
Test Well-3
Upper Lateral
Upper Lateral
Lower Lateral
Stage-1
Weighted Spacer
60 bbl
60 bbl
60 bbl
60 bbl
Gel Spacer
60 bbl
60 bbl
60 bbl
60 bbl
Brine Spacer
60 bbl
60 bbl
60 bbl
60 bbl
Solvent Pill
45 bbl
35 bbl
35 bbl
40 bbl
Displacement Brine (75 pcf)
NA
350 bbl
390 bbl
380 bbl
Gel Spacer*
NA
70 bbl
70 bbl
140 bbl
Weighted Spacer
30 bbl
30 bbl
30 bbl
30 bbl
Gel Spacer
30 bbl
30 bbl
30 bbl
30 bbl
Brine Spacer
30 bbl
53 bbl
40 bbl
67 bbl
Solvent Pill
35 bbl
45 bbl
40 bbl
35 bbl
75 pcf CaCl2 Brine
75 pcf NaCl Brine
75 pcf NaCl Brine
75 pcf NaCl Brine
Stage-2
Displacement Brine**
(2-3 hole volumes until clean
returns)
*Spotted in open hole prior to stinging out of the sand screen PBR
**Displacement after setting production packer
Table 7. OBM spacer fluids pump sequence and volumes
Test #1
Offset #1
Offset #2
Feb. 2010
Aug. 2007
Jan. 2002
*Prod Rate %
110
41
100
Water Cut %
5.0
59.1
36.3
Test #2
Offset #3
June 2010
Feb. 2008
*Prod Rate %
157
100
Water Cut %
0
4.3
Date
Date
Test #3
Date
June 2010
*Prod Rate %
145
Water Cut %
0
Same offset well with Test #2
well above
*Compared to offset wells with acid cleanup and severe losses
Table 8. Well production performance of test well and offset well
SPRING 2013
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62884araD3R1_ASC026 3/15/13 11:25 PM Page 9
ACKNOWLEDGMENTS
Photos 6a and 6b. Displacement brine returns after first-stage treatment and after
second-stage treatment.
for the permission to present and publish this article. We
would also like to thank all the members of the formation
damage and stimulation laboratory for their support towards
the success of the laboratory work and field trials. We also
acknowledge the technical support of members of the Drilling
Fluids and Cement Unit and Saleh M. Ammari at the time of
the project.
U.A.E., November 11-14, 2012.
REFERENCES
Fig. 7. Pump and displacement brine data for lower lateral in test Well-3.
content was recorded for the test Well-3 upper lateral), Photos
6a and 6b. The post-completion production test indicated a
production rate of 145% (0% water cut) compared to the
same offset wells used for the test Well-2 assessment. The well
performance was appraised as better than that of the offset
wells that had breaker fluids treatment while encountering
severe losses at completion, Table 8.
CONCLUSIONS
1. Reactive mud cake breaker fluids are incapable of effectively removing OBM filter cake in long open hole horizontal wells located across high permeability sandstone reservoirs without inducing severe fluid losses and emulsion
induced formation damage as a result of the OBM, completion and formation fluids mixing together.
2. A two-stage circulation treatment with acid-free MSFs has
been proven effective in facilitating open hole sandstone
wellbore cleanup by altering the wettability of the oily filter
cake and mud particles without completely removing the
filter cake and so inducing fluid losses that need to be controlled with more damaging materials.
3. It is recommended to evaluate the probability and potential
risk of severe losses with breaker fluid application to the
filter cake by reviewing the completion and cleanup fluid
performance in offset wells prior to using the acid-free
MSFs.
4. The surfactant/solvent fluids were effective in dispersing
and water-wetting the OBM DIFs. The OBM base oil and
formation brine were found to be compatible with the surfactant/solvent pills as no precipitation or emulsion was observed at bottom-hole conditions. The generation of a Winsor
Type III middle-phase microemulsion was confirmed.
18
SPRING 2013
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20
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BIOGRAPHIES
Peter I. Osode is a Petroleum Engineer
Specialist with the Formation Damage
and Stimulation Unit in Saudi
Aramco’s Advanced Technical Services
Division.
He has over 30 years of diverse
upstream industry experience spanning
wellsite petroleum engineering operations, production
technology (well and reservoir management, production
optimization and production chemistry) and drilling and
completion fluids management. Peter started his career
with Baroid/Halliburton as a Technical Sales Engineer
before moving to Shell Petroleum Development Company
in Nigeria and Shell International’s affiliate-Petroleum
Development Oman (PDO) in Oman. He has participated
in a number of Shell Global E&P Well Performance
Improvement projects and was the subject matter expert on
drilling fluids performance assessment process prior to
joining Saudi Aramco in 2009.
Peter received his B.S. degree with honors in Petroleum
Engineering from the University of Ibadan, Ibadan,
Nigeria.
He is an active member of the Society of Petroleum
Engineers (SPE) International and has authored a number
of published technical papers. Peter is currently involved in
formation damage evaluation of reservoir drilling and
completion fluids.
Msalli Al-Otaibi joined Saudi Aramco
in 2005 and began working with the
Formation Damage and Stimulation
unit of the Exploration and Petroleum
Engineering Center Advanced Research
Center (EXPEC ARC) as a Petroleum
Engineer. His work experience includes
formation damage evaluation and prevention strategies for
exploration drilling, reservoir development and water
injection projects in addition to impaired well diagnosis
and remedial treatments.
Msalli was a principal member of the focused team
tasked with promoting innovation in Saudi Aramco
through the development and launching of the first
Innovation Tournament (InTo) in 2010. He has been an
active member in the Society of Petroleum Engineers (SPE)
by publishing seven technical papers and leading the Young
Professionals (YP) and Students Outreach committee of the
SPE-Saudi Arabia Section (SAS) for 2010/2011. Also,
Msalli served as the 2010/2011 SPE-SAS representative on
the North Africa and Middle East (MENA) YP committee.
He received his B.S. degree in Chemical Engineering
from Louisiana State University, Baton Rouge, LA, in
2005. In 2011, Msalli received his M.S. degree in Chemical
Engineering from KFUPM. He is currently pursuing his
Ph.D. degree in Petroleum Engineering at the Colorado
School of Mines, Golden, CO.
62884araD3R1_ASC026 3/15/13 11:25 PM Page 12
Khalid H. Bin Moqbil started his
petroleum engineering career in Saudi
Aramco’s Exploration and Petroleum
Engineering Center – Advanced
Research Center (EXPEC ARC) in
2005. His area of interests include
studies in formation damage related
aspects of reservoir drilling, completion and well
stimulation fluids in addition to water injection studies.
Khalid is currently working with the Gas Reservoir
Management Department where he is involved with gas
production optimization and reservoir management
projects.
In 2005, Khalid received his B.S. degree in Chemical
Engineering and in 2011, he received his M.S. degree in
Petroleum Engineering along with a graduate certificate in
Smart Oil Field Completions, all from the University of
Southern California, Los Angeles, California.
He is an active member of the Society of Petroleum
Engineers (SPE) and has authored and coauthored several
SPE technical papers.
Khaled A. Kilany has over 25 years of
industry experience while working as a
Reservoir and Production Engineer. He
started his career in the oil fields as a
Production Engineer working from
1986 to 1990, and then Khaled
switched to reservoir engineering,
working as a Reservoir Simulation and Reservoir
Management Specialist in several international companies
in Egypt, Canada and the Gulf area, including AGIP in
Egypt, the Kuwait Oil Company and Shell International in
Canada and Oman prior to coming to Saudi Aramco.
Since joining Saudi Aramco in August 2005, Khaled has
worked as a Senior Reservoir Engineer with the Northern
Area Reservoir Management Department where he was
involved in introducing innovative completion equipment
and production optimization techniques in Safaniya field.
Khaled’s experience here includes his participation in
several reserve assessment studies, short- and long-term
production forecasts, waterflood management and full field
development plans. He currently leads a sub-team of the
Manifa Incremental Project Team that is tasked with the
largest ongoing offshore incremental development project
in the company.
In 1982 Khaled received his B.S. degree in Petroleum
Engineering from Cairo University, Giza, Egypt.
Eddy Azizi has over 17 years of
experience that consolidates his current
position as Senior Production Engineer
within the multidisciplinary Northern
Area Production Engineering team in
Saudi Aramco. He has worked in both
offshore and onshore environments at
both Shell International and Saudi Aramco. Eddy started
his career in the oil field as a Process Engineer for 2 years,
and then worked as a Well Site Drilling/Completion
Engineer for 2 years and one year as a Well Services
Supervisor in the field. He later worked as a Production
Technologist and/or Production Engineer for the next 12
years with involvement in several field development
assessment studies/plan, short- and long-term production
forecasts, sand management, production system
modleing/nodal analysis and ESP operations and
unconventional oil production systems.
Eddy has been involved in a number of new production
optimization initiatives, which has resulted in improved
stimulation fluid placement, zero flaring, and completion
integrity management in addition to reduced coil tubing
utilization in Safaniya while he currently leads the Well
Integrity team working on the Qatif field.
Eddy received his B.S. degree (First class honors) in
Chemical Engineering from London University, London,
U.K., in 1995.
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Selecting Optimal Fracture Fluids, Breaker
System and Proppant Type for Successful
Hydraulic Fracturing and Enhanced Gas
Production – Case Studies
Authors: Dr. Zillur Rahim, Dr. Hamoud A. Al-Anazi and Adnan A. Al-Kanaan
ABSTRACT
Hydraulic fracturing is required to commercially produce low to
moderate permeability gas reservoirs. The selection of fracturing
fluids, additives and proppant types is a major component when
designing and implementing a hydraulic fracturing treatment.
A viscous, unbroken fracture fluid that remains after the treatment compounds the effects of fracture face skin and causes
severe deterioration to proppant conductivity. With the advancement of technology, many novel fracture fluid systems
are now available in the industry with reduced polymer concentration to preserve reservoir and proppant integrity. The
advantages of these fluids include less formation damage,
lower cost and reduced treatment pressure. Subsequent to the
fracture operation, an aggressive breaker treatment is often
necessary to effectively clean up the fracture and restore proppant conductivity. Proppant conductivity plays a tremendous
role in the post-fracture production enhancement, and any
damage left from the fluids can impair well potential considerably. Similarly, the correct choice of proppant, based on the rock
strength, reservoir fluid properties, expected production rate,
pressure and temperature, is important. Proppant type and
scheduling determine the ultimate propped fracture geometry
that controls the gas flow from the reservoir to the wellbore.
The application of new technologies in combination with
better job design is ongoing to obtain improved results in the deep
sandstone reservoirs of Saudi Arabia. In the process of optimization, fluids along with their gel type, polymer concentration
and additives have been modified and changed to provide better
results. Similarly, proppant size, type and scheduling have been
optimized. Different types of aqueous-based fracturing fluids
with various polymer loadings, as well as hybrid systems and
viscoelastic surfactant (VES) fluids for deep and high temperature reservoirs are currently in use. Several case studies provided
in this article demonstrate how the critical fracturing parameters
have progressed with time, been customized and can now be
made to fit the reservoir conditions to make a noticeable impact
on well productivity and recovery.
INTRODUCTION
The primary purpose of hydraulic fracturing treatment is to
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SPRING 2013
enhance productivity. The unconventional gas reservoirs will
not produce unless a long, conductive fracture is in place. A
successful treatment can improve well production and sustainability; however, fracturing is never optimum, and the industry
has been continuously working at different fronts to obtain improved results. Some of these fronts include a complete change
in the fluid system so that the gel damage is reduced and the
fluids pumped can be flowed back efficiently. The gel breaking
agent is therefore an important ingredient, and the right
amount and type of that agent are some of the key factors that
help minimize proppant conductivity damage from gel residue.
This article focuses more on the gel and polymer systems and
the breaking agents.
On the other hand, the proppant system and pump schedule
have also been revised. The change is intended to provide
longer and more conductive fractures and to reduce chances of
premature screen-outs.
This article also deals with many important issues and illustrates the gradual progression in the application of high-end
technology, thereby improving overall hydraulic fracturing
treatments to achieve sustained production rates. Many examples in this article confirm the successes achieved through the
identification of problems and a follow-up with remedial actions.
FRACTURE FLUIDS CHEMISTRY
Water-based fracturing fluids are the most common types and
are widely used. The viscosity is obtained by mixing 20-70 lb
of guar polymer, or its derivative, per 1,000 gal of water. This
mixture is known as the base gel and typically provides 30-50
cP viscosity at surface conditions1-3.
Developed around 1968, cross-linked agents were added to
linear gels, resulting in a complex, high-viscosity fracturing
fluid that provides higher proppant transport performance
than do linear gels. Cross-linking also reduces the need for
fluid thickener and extends the viscous life of the fluid. The
fracturing fluid remains viscous until a breaking agent is introduced to break the cross-linker, and eventually, the polymer.
Although cross-linkers make the fluid more expensive, they
can improve hydraulic fracturing performance considerably.
When a gel is cross-linked, the viscosity can increase on
the order of 100 times or more. The base gel and polymer
62884araD4R1_ASC026 3/15/13 11:27 PM Page 2
cross-linker are the two most critical elements to consider in a
fracturing fluid.
The most frequent base gel and cross-linker used in the industry are hydroxyethyl cellulose (HEC) and hydroxypropyl
guar (HPG), respectively. Many different products are now
available to address fracturing of unconventional reservoirs,
and the fluids often selected are highly dependent on the permeability of the formation, the reservoir fluid and the reservoir
pressure of the candidate well.
Table 1 provides some of the components of fracture fluids
commonly used and their respective functions during the treatment. The chemical components of some of the additives are
given in Table 2.
As the fracturing fluid is pumped at high rates, it creates an
induced fracture. The proppant is transported along with the
fluid. A certain portion of the fluid leaks off into the formation
while a cake of concentrated guar polymer is formed at the
fracture face. This cake can be like an elastic membrane, and if
not removed, can severely damage the reservoir flow capacity.
Many major aspects need to be considered when selecting
the most appropriate fluid to ensure good results after the fracture
Frac Fluid Additives
Functions
Breaker
Breaks gel and polymer after
treatment and fracture closure.
Cross-linked Agent
Maintains fluid viscosity as
temperature increases.
Base Gel
Thickens the water in order to
suspend the sand.
Iron Control Agent
Prevents precipitation of metal
oxides.
KCl
Creates a brine carrier fluid.
Proppant
Is main fracturing component
providing conductivity.
Surfactant
Minimizes formation damage,
leaves no residue, reduces
friction.
Table 1. Main fracture fluid additives and their functions
Frac Fluid Additives
• Create sufficient width to the fracture.
• Provide enough viscosity to transport proppant at the
designed concentration.
• Resist pressure and shear degradation as the treatment
progresses.
• Provide lower friction loss to reduce injection pressure.
• Include sufficient additives to control vital fluid
properties such as pH level and viscosity.
• Provide adequate and effective breaker systems to break
the polymer gel once treatment is complete and the
fracture has closed.
• Control fluid loss and provide optimum fracture
geometry.
• Provide higher regained permeability of the proppant
pack.
Use of viscoelastic surfactant (VES) fluids, a polymer-free,
low surface tension system, is a good option in fracturing
treatment4. These fluids use surfactants with inorganic salts to
create an ordered structure resulting in increased viscosity and
elasticity5. The initial two shortcomings inherent with other
fluids, i.e., low viscosity at high temperatures due to thermal
thinning and the lack of internal breaking mechanisms, are
supposedly overcome by the new fluid formulation. These fluids are insensitive to salinity, are compatible with N2 and CO2,
and do not require clay control agents5. The fluid does not
form filter cake; therefore, there is no plugging of the formation, and the post-treatment retained permeability is high5. Basically, VES uses surfactants in combination with inorganic salts to
create ordered structures, which eventually results in increased
viscosity and elasticity. The fluids tend to be shear degradable
but can transport proppant with lower loading and without
the comparable viscosity requirements of conventional fluids.
SHEAR AND TEMPERATURE TOLERANCE OF
FRACTURE FLUIDS
Chemical Components
Gelling Agent
Hydroxyethyl Cellulose/
Hydroxypropyl Guar
Proppant
Quartz Sand, Ceramics
Cross-linker
Borate Salt
Breaker
Ammonium Persulfate
Surfactant
Isopropanol
Table 2. Fracture fluid chemistry
treatment. Most importantly, the fluid must be compatible
with the reservoir pressure-volume-temperature (PVT) properties so that there remains absolutely no chance of creating formation damage. Other aspects to consider include how to:
One of the most critical aspects of selecting a fracture fluid is
to ensure that the viscous characteristics are maintained until
the treatment is over and the fracture has closed. Many fracture fluid systems are affected by pressure and temperature,
Fig. 16. Traditionally, complex fracture fluid systems with high
gel and polymer loading and a high concentration of additives
have been used for treatments in complex reservoirs, such as a
high-pressure/high temperature environment. A number of
fluid additives are used, resulting in a complex chemistry that
must be kept in a tight range to ensure quality fluid performance. Some current new fluids have been tested in the laboratory
SPRING 2013
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Fig. 2. Effect of shear degradation on fracture fluid types4.
BREAKERS
Fig. 1. Effects of pressure and temperature on fracture fluid viscosity.
first and then used in the actual fracturing treatments of a few
Saudi Arabian gas wells. Although there is no single, all-purpose fluid fit for any application, and every well must be evaluated for selecting the most appropriate fluid characteristics, the
newer fluids with fewer additives and a dual cross-linker (borate and zirconate) system have proven good results. Typically,
the borate cross-linkers are shear tolerant but are affected by
temperature. In contrast, the zirconate cross-linkers are temperature resistant but shear degradable. The laboratory test results for different fluid specifications are illustrated in Fig. 2.
The dual cross-linker system therefore is considered to be an
appropriate type of fluid to use.
GEL DAMAGE AND TRAPPED FLUIDS
The gel and the cross-linked fluids pumped during fracture
treatment cannot be fully recovered during production. In different field studies, it has been found that 60% to 80% of the
pumped fluids can be recovered over a long period of time.
The amount of fluids recovered decreases and the recovery
time increases, in low permeability, tight reservoirs. Palmer described a “check valve” effect where the width of the fracture
decreases after treatment and does not allow larger size polymers to flow back7. Also, during injection, the hydraulic gradient is higher and carries the polymers farther away. During the
flow back, the hydraulic gradient is much lower and does not
generate sufficient force for the fluids to be produced back,
therefore, the need for polymer breakers to reduce the injected
fluid viscosity is as low as possible.
In conventional reservoirs, the gel damage is compensated
for by the reservoir permeability and increased apparent wellbore radius due to hydraulic fracturing. In tight formations,
and also in naturally fractured reservoirs (therefore in coalbed
methane), the effect of the gel damage is more severe.
24
SPRING 2013
Using the appropriate type and volume of breakers is of prime
importance. Though a gel is needed to create the fracture and
carry the proppants, it also has to degrade and be produced
back to leave a clean, high conductivity, propped fracture
behind.
Breakers are usually mixed with the fracturing fluid during
pumping. Most breakers are typically acids, oxidizers or enzymes. The breakers include ammonium persulfate, ammonium
sulfate, copper compounds and glycol. Types include timerelease, shear-release or temperature dependent breakers4, 8.
Residue-after-break tests have shown that enzyme breakers
leave fewer residues than oxidative breakers used at the same
temperature. Polymer degradation by enzymes continues for a
much longer time, so has a cleaner effect on the gel residue
after a fracture treatment.
Breaker concentration is important for proper cleanup of
the fracture. Improved well performance, indicated by higher
flow rate and sustainability, has been observed when using
higher than normal breaker concentrations. The results are
related to achieving and maintaining higher proppant conductivity as the magnitude of gel damage is reduced.
Basically, two types of breakers are used. The enzymes of
the first one are mixed with the fracturing fluids at various
concentrations as the job is being pumped. Introduction of the
second one is delayed through encapsulation; the capsules
break and release their ingredients under certain temperature
and stress conditions, which typically happen post-treatment
when the fracture closes. Figure 3 presents some laboratory experiments on a certain breaker showing the effect of gel breaking and the loss of viscosity as functions of concentration.
USE OF FRACTURE FLUIDS AND BREAKERS IN SAUDI
ARABIAN WELLS
Since the inception of hydraulic fracturing, many different types of
fracturing fluids have been used in the sandstone gas formations
62884araD4R1_ASC026 3/15/13 11:27 PM Page 4
in Saudi Arabia9. The fluid volume size, gel loading and additives are customized to fit the needs of a particular field and
reservoir. The fluid quality and type have also advanced during
this time, and new fluids systems are progressively being used.
Figure 4 shows a comparison chart of the average percentage of basic fracture fluid additives (x-axis) used in 2011 compared to 2008 in a few of the Saudi Arabian wells. Other than
differences in some of the fluid chemistry, it is noticeable how
the quantity of some of the ingredients has increased over time.
The pH control and bactericide are used to maintain the integrity of the fluids and provide compatibility with the formation. The cross-linker concentration was increased to provide
better proppant carrying capacity and generate a larger fracture width. The breaking agent in particular has increased by
more than 60%, indicating the importance of ensuring a clean
fracture after the treatment and a quick flow back of the degraded gel. Figure 5, which shows the breaker-to-gel ratio used
in the treatment of about 100 wells analyzed since 2000, illustrates the trend toward using increased breaker concentrations.
This change in the fracturing program is due to the fact that a
higher concentration of breaking agent is conducive in achieving cleaner fractures, thereby leading to higher productivity
wells. The field results confirmed the benefits of using a higher
breaker amount, so the trend continues. The gel loading did
not change, Fig. 6, showing that the proppant transport and
fracture dimensions were being achieved as per expectation. In
fact, attempts have been made to decrease the gel loading without compromising fracture quality so as to incur less damage
to the proppant and formation.
Figure 7 presents the use of different breaker types and their
respective quantities as a function of the total gel volume. The
choice and use of both oxidative and encapsulated breakers,
along with their specific activation characteristics, are important to cover the range of temperature between the cooled
down fracture during the treatment and the reservoir temperature. Therefore, the proper mix of low temperature and high
temperature (LT and HT) breaking agents ensures that the
breaking of gel initiates when the fracture closes and is relatively cool, and continues for a prolonged period as the fracture eventually attains reservoir temperature.
EXAMPLE WELLS
The effects of breaking down the gel are seen in results from
two recent vertical wells where additional breakers were
pumped after it was realized that the post-treatment production
rates were not up to the expectation based on open hole log data
and rates from some of the offset wells. The inflow performance
Fig. 5. Breaker-to-gel ratio in gas wells between 2000 and 2012.
Fig. 3. Effect of gel concentration on fracture fluid viscosity6.
Fig. 6. Normalized gel loading showing a constant trend.
Fig. 4. Change of additive quantity between 2008 and 2011.
Fig. 7. Breaker-to-gel ratio for different breaker types.
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cern, appropriate measures should be taken, as was done with
the two wells illustrated here. The production rate before and
after the breaker treatments for Well-B, Fig. 10, shows that the
well stabilized at 18 MMscfd at a high flowing wellhead pressure after the treatment. The reservoir lithology, porosity and
saturation of the two wells are comparable.
ADDITIONAL BREAKER TREATMENT
Fig. 8. Before and after breaker treatment IPR, Well-A.
The polymer removal breaker treatment used in the two wells
consisted of a high temperature, high concentration, water soluble breaker system. The purpose was to efficiently break any
residual gel in the proppant pack and also leak off into the formation and clean up the matrix during flow back. Among
other components, a bactericide and pH buffer were added,
along with a corrosion inhibitor to preserve fluid integrity and
make it compatible with the reservoir as well as with the tubulars. Nitrogen was added to enhance flow back. In addition,
methanol was pumped to treat any water blockage in the
fracture and formation. Removal of water blockage should be
considered because it can hinder gas flow significantly10.
PROPPANT OPTIMIZATION
Fig. 9. Before and after breaker treatment IPR, Well-B.
Good proppant selection is an integral part of successful hydraulic fracturing. Among the different types of proppants
available, the major ones used in Saudi Aramco are the lightweight ceramics and the intermediate/high density ceramics,
some of which are resin coated proppants (RCP). RCP is routinely used as a tail-end in the pumping treatment to prevent
proppant flow back, and this process has been working very
well. The main criteria of proppant selection depend on the
conductivity requirement at downhole conditions. The evaluation is usually done based on the contrast between the flow
capacity of the fracture and the reservoir, known as the dimenkf Wf
sionless fracture conductivity, FCD= kmLf .
Selection criteria are also based on reservoir pressure and
temperature, embedment, multiphase flow and crushing. Other
very important aspects to take into account while selecting the
proppant are the flow convergence effects, particularly in
transverse fractures, non-Darcy flow, gel damage, and nonoptimal proppant concentration and placement, as well as reduced
conductivity due to fines migration and pressure cycling.
Maintaining a high conductivity fracture has always proven
to be a preferred option since it overcomes many of the above
mentioned problems that can reduce gas production rate. A
proppant type that shows high conductivity at higher stress in
the laboratory, however, can fall short in the field, failing to
maintain that level of conductivity due to non-Darcy effects or
flow convergence11. The non-Darcy flow permeability, which
is the effective permeability, kF, can be computed from the
laminar flow equation by relating Darcy permeability, kD, with
the flow turbulence expressed by Reynold’s number, NRE, using
kD
the equation: kF=1+NRe . Therefore, the higher the Reynold’s
—————
Fig. 10. Flow rate and pressure before and after breaker treatment, Well-B.
curves from Well-A and Well-B presented in Figs. 8 and 9, respectively, clearly show the improved rates from both wells,
where the increase of absolute open flow ratio ranged from
25% to over 100%. The measured rate and pressure are plotted on the graph. The improvement varies, depending on the
initial treatment schedule and what was pumped in terms of
gel loading and breaker quality. The optimum procedure is to
take into consideration all damage and cleanup possibilities so
as to optimize the fluids pumped during the treatment. That
way, added intervention in the well is avoided, saving time and
additional expenditure. Consequently, post-frac production
analysis must be conducted on all wells, and if there is a con26
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62884araD4R1_ASC026 3/15/13 11:27 PM Page 6
the post-fracture expected rate is not achieved, although fracture treatment was pumped as designed. When this happens,
well performance has been compromised because of gel residue
in the fracture and suboptimal cleanup. The following are
some of the key points drawn from this article.
• Efficient polymer breaker treatment contributes to
higher well productivity. Low polymer loading and/or
an adequate amount of breaker is necessary for a
complete post-fracture cleanup.
Fig. 11. Normalized rate loss as a function of fracture conductivity for different
reservoir permeabilities.
• Methanol or similar surface tension reducing agents
should be routinely used to minimize water blockage
effects. Wells have shown significant improvement after
such treatments are conducted.
• Additional pressure drop due to non-Darcy flow or flow
convergence phenomenon occurring in transverse
fracture geometry may be significant and will contribute
to low well productivity.
• The gas production rate is also adversely affected by the
presence of condensate.
• The use of high strength and high conductivity
proppant, without risking embedment or crushing, is
essential to maintain good connectivity between the well
and the formation.
Fig. 12. Normalized gas rate illustrating both laminar and non-Darcy effects for
different reservoir permeabilities.
number (high flow rate), the lower the effective permeability
will be. In the proppant fracturing jobs performed in Saudi
Arabian gas wells, ensuring an effective conductivity of more
than 3,000 md-ft has become the norm. Even though in the
tight reservoirs this number seems to be high, the higher conductivity helps maintain a long-term rate in reservoirs where
condensate dropout becomes a challenge.
Some examples of non-Darcy-related rate loss as a function
of some specific reservoir properties in Saudi Arabian gas fields
are provided in Figs. 11 and 12. The rate loss is pronounced in
high permeability wells due to their high flow rates, and this
number can be significant. For a fracture conductivity of 1,000
md-ft, the rate loss in a 5 md reservoir can be as much as 35%,
whereas there will be no loss in a 0.1 md reservoir. Even in a 1
md reservoir, the loss will be negligible; therefore, the selection
of proppant type and concentration should be based on reservoir flow capacity. If proppant crushing and embedment conditions are met, high permeability proppants are always
preferred, pumped at high concentration so as to achieve
significant propped fracture width at fracture closure.
CONCLUSIONS
Hydraulic fracturing is a necessary technique to improve gas
production from tight or conventional reservoirs. Many times
• Higher proppant loading is equally effective to provide
sufficient fracture width, which is directly related to the
ultimate conductivity of the created fracture.
ACKNOWLEDGMENTS
for the permission to present and publish this article.
This article was presented at the SPE Unconventional Gas
Conference and Exhibition, Muskat, Oman, January 28-30,
2013.
REFERENCES
1. Economides, M.J. and Nolte, K.G.: Reservoir Stimulation,
3rd edition, New York: John Wiley and Sons, 2000, p. 818.
2. Gall, B.L. and Raible, C.J.: “Molecular Size Studies of
Degraded Fracturing Fluid Polymers,” SPE paper 13566,
presented at the SPE Oil Field and Geothermal Chemistry
Symposium, Phoenix, Arizona, April 9-11, 1985.
3. Langedijk, R.A., Al-Naabi S., Al-Lawati H., Pongratz, R.,
Elia, M.P. and Abdulrab, T.: “Optimization of Hydraulic
Fracturing in a Deep, Multilayered, Gas-Condensate
Reservoir,” SPE paper 63109, presented at the SPE Annual
Technical Conference and Exhibition, Dallas, Texas,
October 1-4, 2000.
4. Courtesy of Schlumberger.
5. Gupta, S.: “Unconventional Fracturing Fluids: What,
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Where, and Why,” Baker Hughes, Tomball Technology
Center, Tomball, Texas.
6. England, K.W. and Parris, M.D.: “The Unexpected
Rheological Behavior of Borate Cross-linked Fluid,” SPE
paper 140400, presented at the SPE Hydraulic Fracturing
Technology Conference, The Woodlands, Texas, January
24-26, 2011.
7. Palmer, I.D., Frayar, R.T., Tumino, K.A. and Puri, R.:
“Comparison between Gel-Fracture and Water-Fracture
Stimulations in Black Warrior Basin,” SPE paper 23415,
presented at the Coalbed Methane Symposium, Tuscaloosa,
Alabama, May 13-16, 1991.
8. Courtesy of Halliburton.
9. “2009-2011 Gas Program,” Saudi Aramco Gas Reservoir
Management Division internal documentation.
10. Holditch, S.A.: “Factors Affecting Water Blocking and
Gas Flow from Hydraulically Fractured Gas Wells,”
Journal of Petroleum Technology, Vol. 31, No. 12,
December 1979, pp. 1,515-1,524.
11. Gidley, J.L.: “A Method for Correcting Dimensionless
Fracture Conductivity for non-Darcy Flow Effects,” SPE
Production Engineering, Vol. 6, No. 4, November 1991,
pp. 391-394.
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BIOGRAPHIES
Dr. Zillur Rahim is a Petroleum
Engineering Consultant with Saudi
Aramco’s Gas Reservoir Management
Department (GRMD). He heads the
team responsible for stimulation
design, application and assessment for
GRMD. Rahim’s expertise includes
well stimulation, pressure transient test analysis, gas field
development, planning, production enhancement, and
reservoir management. Prior to joining Saudi Aramco, he
worked as a Senior Reservoir Engineer with Holditch &
Associates, Inc., and later with Schlumberger Reservoir
Technologies in College Station, TX, where he used to
consult on reservoir engineering, well stimulation, reservoir
simulation, and tight gas qualification for national and
international companies. Rahim is an Instructor of
petroleum engineering industry courses and has trained
engineers from the U.S. and overseas. He developed
analytical and numerical models to history match and
forecast production and pressure behavior in gas reservoirs.
Rahim developed 3D hydraulic fracture propagation and
proppant transport simulators and numerical models to
compute acid reaction, penetration, and fracture
conductivity during matrix acid and acid fracturing
treatments.
Rahim has authored 65 Society of Petroleum Engineers
(SPE) papers and numerous in-house technical documents.
He is a member of SPE and a technical editor for the
Journal of Petroleum Science and Engineering (JPSE).
Rahim is a registered Professional Engineer in the State of
Texas and a mentor for Saudi Aramco’s Technologist
Development Program (TDP). He is an instructor of the
Reservoir Stimulation and Hydraulic Fracturing course for
the Upstream Professional Development Center (UPDC) of
Saudi Aramco. Rahim is a member of GRMD’s technical
committee responsible for the assessment and approval of
new technologies.
Rahim received his B.S. degree from the Institut
Algerien du Petrole, Boumerdes, Algeria, and his M.S. and
Ph.D. degrees from Texas A&M University, College
Station, TX, all in Petroleum Engineering.
62884araD4R1_ASC026 3/15/13 11:27 PM Page 8
Dr. Hamoud A. Al-Anaziis the General
Supervisor of the North Ghawar Gas
Reservoir Management Division in the
Gas Reservoir Management
Department (GRMD). He oversees all
work related to the development and
management of huge gas fields like
Ain-Dar, Shedgum and ‘Uthmaniyah. Hamoud also heads
the technical committee that is responsible for all new
technology assessments and approvals for GRMD. He
joined Saudi Aramco in 1994 as a Research Scientist in the
Research & Development Center and moved to the
Exploration and Petroleum Engineering Center – Advanced
Research Center (EXPEC ARC) in 2006. After completing
a one-year assignment with the Southern Area Reservoir
Management Department, Hamoud joined the Gas
Reservoir Management Division and was assigned to
supervise the SDGM/UTMN Unit and more recently the
HWYH Unit. With his team he successfully implemented
the deepening strategy of key wells that resulted in a new
discovery of the Unayzah reservoir in UTMN field and the
addition of Jauf reserves in the HWYH gas field.
Hamoud’s areas of interests include studies of formation
damage, stimulation and fracturing, fluid flow in porous
media and gas condensate reservoirs. He has published
more than 50 technical papers at local/international
conferences and in refereed journals. Hamoud is an active
member of the Society of Petroleum Engineers (SPE) where
he serves on several committees for SPE technical
conferences. He is also teaching courses at King Fahd
Saudi Arabia, as part of the Part-Time Teaching Program.
In 1994, Hamoud received his B.S. degree in Chemical
Engineering from KFUPM, and in 1999 and 2003,
respectively, he received his M.S. and Ph.D. degrees in
Petroleum Engineering, both from the University of Texas
at Austin, Austin, TX.
Adnan A. Al-Kanaan is the Manager of
the Gas Reservoir Management
Kingdom to meet its ever increasing energy demand. He
oversees the operating and business plans of GRMD, new
technologies and initiatives, unconventional gas development programs, and the overall work, planning and
decisions made by his more than 70 engineers and
technologists.
Supervisor for the Gas Reservoir Management Division
under the Southern Reservoir Management Department for
3 years, heading one of the most challenging programs in
optimizing and managing nonassociated gas fields in Saudi
Aramco.
Adnan started his career at the Saudi Shell Petrochemical
Company as a Senior Process Engineer. He then joined
Saudi Aramco in 1997 and was an integral part of the
technical team responsible for the on-time initiation of the
two major Hawiyah and Haradh Gas Plants that currently
process more than 6 billion cubic feet (bcf) of gas per day.
Adnan also directly managed the Karan and Wasit fields —
two major offshore gas increment projects — with an
expected total production capacity of 4.3 bcf of gas per day.
test analysis, simulation modeling, reservoir characterization, hydraulic fracturing, reservoir development
planning and reservoir management.
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Assessment of Multistage Stimulation
Technologies as Deployed in the Tight Gas
Fields of Saudi Arabia
Authors: Mohammed A. Al-Ghazal, Saad M. Al-Driweesh, Fadel A. Al-Ghurairi, Abdulaziz M. Al-Sagr and
Mustafa R. Al-Zaid
ABSTRACT
The increasing demand for oil and gas resources to support
worldwide development plans means that the petroleum industry is always actively engaged in exploring new frontiers in
drilling and production, including tight multilayered reservoirs.
It is becoming evident more than ever that producing the most
oil and gas out of drilled reservoirs is an absolute necessity.
Accordingly, completion techniques have presented themselves
as a crucial well construction parameter, one that is key to
optimally producing wells.
Several completion techniques have been exhaustively trial
tested in Saudi Aramco to determine the most successful completion mode for each reservoir. Among those various techniques, open hole multistage stimulation has demonstrated
superior performance in minimizing skin damage and maximizing reservoir contact through efficient propagation of
fracture networks within the rock matrix.
Overall, the production results from wells completed using
open hole multistage stimulation systems — as deployed in the
tight gas fields of Saudi Arabia — have been very positive. Various open hole multistage completion systems were run over
approximately 40 wells. While production results varied where
this new technology was utilized, the majority of the wells
have met or exceeded the pre-stimulation expectations for gas
production.
This study highlights these systems and discusses their impact
on wells during the fracturing operation and the final stabilized production. This study will also present some case studies
in multistage fracturing operations and investigate the operational impact of such operations on productivity enhancement.
With correct implementation, the findings from this study
should increase the probability of having a more successful
multistage stimulation job from a productivity standpoint.
Hydraulic fracturing is required in tight multilayered reservoirs for increased oil and gas recovery. Effective wellbore
compartmentalization by means of open hole packers, especially in low and nonuniform permeability reservoirs, is key to
successful multistage stimulation operations. It is, therefore,
important to describe and compare the modes of operation of
stimulation systems and the effects of the various downhole
conditions on the main open hole packer designs available to
our industry today.
Since the beginning of 2007, a total of 40 wells in the tight
gas fields of Saudi Aramco’s Southern Area have been completed with open hole multistage stimulation systems. Target
formations have spanned the Khuff B and C carbonates and
the pre-Khuff (Unayzah) sandstone reservoir. Hole sizes have
included both 8⅜” and 5⅞”, and the number of stages per well
has been as high as seven. Figures 1 to 6 show more details
about the 40 wells where open hole multistage stimulation systems were run by the various technology suppliers. Out of the 40
wells:
Fig. 1. Number of wells completed per supplier.
INTRODUCTION
While the well trajectory planning, reservoir characterization
and completion design are important determinants of well productivity, open hole multistage stimulation completion has
demonstrated that it can have significant effects on long-term
stabilized production and reservoir draining efficiency.
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SPRING 2013
Fig. 2. Number of MSS wells completed per year per supplier.
62884araD5R1_ASC026 3/15/13 11:29 PM Page 2
enough flowing wellhead pressure (FWHP) to connect
directly to the trunk line.
• Two wells (13%) have exceeded the target rates, but
could not be connected to the trunk line due to
insufficient FWHP.
• Five wells (12.5%) could not meet the expected poststimulation target rates.
Fig. 3. Percentage success in reaching target depth per supplier.
DEFINITION OF AN UNBALANCED AND BALANCED
SYSTEM
An unbalanced open hole multistage completion system design
means that the lowest stage in the completion is open at the
bottom to allow fracturing out of the toe stage, Fig. 7. This is
opposed to a balanced system where the first stage stimulation
zone is between two packers, Fig. 8.
COMPARISON OF OPEN HOLE PACKERS
Inflatable Packers
Fig. 4. Percentage success in opening frac sleeves per supplier.
Fig. 5. Percentage success in packer zonal isolation per supplier.
Often referred to as external casing packers (ECPs), these
packers are normally constructed of base pipe similar to the
completion casing/liner/tubing, Fig. 9. The construction is such
that the packer element is mechanically fixed to the outside
diameter (OD) of the base pipe at both ends, leaving an annulus between the pipe’s OD and the element’s inside diameter
(ID). The base pipe would normally have a valve system that
would open at a predetermined pressure to allow tubing fluid to
fill the annulus and “inflate” the element. The valve system
would then trip closed at another predetermined higher pressure
to lock the fluid inside the element and retain the post-inflation
element dimensions and seal against the wellbore. Inherent design limitations of these packers (i.e., their very low differential
pressure capabilities) have discounted their use in open hole
multistage system applications.
Fig. 7. Unbalanced system with the hydraulic fracture sleeve (stage 1) at the
bottom of the lower completion.
Fig. 6. Percentage success in ball seat milling operations.
• 35 wells (87.5%) have exceeded the target production
gas rates.
• 32 wells (80%) have exceeded the target rates with
Fig. 8. Balanced system with the hydraulic fracture sleeve (stage 1) between two
packers.
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element in place. Swell packers are typically between 10 ft and
32 ft long, and they feature various grades and types of rubber.
Upfront design and planning is required so that the proper
packer is selected for each operation (job specific design).
Three factors dictate the downhole performance of swell
packers:
• Bottom-hole temperature (the most determinant factor,
as temperature variations could be crucial).
• Wellbore fluid type (completion, stimulation and
production fluids).
• Ratio of base pipe OD to wellbore ID.
Fig. 9. Inflatable packer element.
Fig. 10a. Swellable packer element.
Fig. 10b. Swellable packer element.
Swell Packers
Often referred to as swellable element packers (SEPs) and/or
reactive element packers (REPs), these packers are also constructed of a base pipe similar to the completion liner/tubing,
Figs. 10a and 10b. With this application, specific rubber is
molded, thermally cured and glued to the base pipe. Sometimes
backup rings are integrated into the design to keep the rubber
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SPRING 2013
Significant pre-job data should be collected for each wellbore section. Once the necessary information is gathered, it is
possible to estimate the packer dimensions (base pipe OD and
element thickness) as well as the swell period required to
achieve the desired pressure rating.
As soon as the element comes into contact with its corresponding fluid (water or hydrocarbon), it begins to swell.
Therefore, to avoid premature swelling, retardant chemicals
are normally mixed in the rubber recipe or otherwise applied
to the element OD, depending on the swell packer supplier
company.
The swell process is a function of time, temperature and
fluid type, so these crucial factors must be carefully observed
during job design and execution.
In swell packers such as that provided by Supplier C, the retardant chemical is applied to the outside of the SEP. This typically creates a huge risk when running in the open hole, as it is
possible that the retardant chemical could be removed or
scraped off, and premature swelling could occur. The optimum
swell packer to use is one where the retardant chemical is
mixed in the rubber, so the possibility of its removal and premature swelling does not occur. Another disadvantage of Supplier C’s swell packer is the 32 ft length with a 5.60” OD,
which makes deployment a major issue when running several
stages in the well and heightens the risk of not reaching the target depth due to mechanical or differential sticking issues. The
shorter the length and the smaller the OD, the better, when
selecting swell packers from the deployment standpoint.
The time to swell could range from hours to weeks depending on well conditions, element design and swell packer supplier company.
MECHANICAL PACKERS
Hydraulically set mechanical open hole packers use rubber
pack off elements, which are compressed when set to form a
seal between the completion and the open hole, Fig. 11. A successful packer design used in the Saudi Aramco Southern Area
gas fields is an open hole packer that features more than one
rubber element.
The setting mechanism of this packer is characterized by a
dynamic setting mode that uses the fracture surface pumping
62884araD5R1_ASC026 3/15/13 11:29 PM Page 4
Fig. 11. Mechanical open hole packer.
pressure to continuously adjust the pack off force on each
element to maintain sealing. When the packer is subject to a
pressure higher than its initial setting pressure, the ratchet will
move further and pack off the element — this not only copes
with borehole changes, but also increases the differential pressure rating due to the additional pack off force delivered to the
element with the increased hydrostatic pressure.
The open hole mechanical packer is approximately 5 ft
long, which makes it readily adaptable to high doglegs and
build rates, facilitating easier reach to target depth.
COMPARISON OF THE EXTERNAL PRESSURE
SLEEVE/PORT TOOLS
Fig. 12. Summary graph showing the history of the hydraulic frac-port openings
on all MSS operations.
The hydraulic fracture sleeve (HFS) provided by Supplier B
(HFS-B; see yellow column in Fig. 12) has encountered problems with opening on some operations to date. On one well, it
took over two days of pressure cycling using coiled tubing
(CT) with jetting acid to finally shift it open. The port was set
to 4,500 psi and finally opened at 7,474 psi, Fig. 13. Well-B
was a similar case, and the sleeve took even longer to open, requiring an application of 8,000 psi, Fig. 14. Finally, on a third
well, the P-sleeve was cycled for three days, first to 7,100 psi
through the wellhead and second to 12,100 psi through a tree
saver, and it still did not open.
Fig. 13. Treatment chart for first well: CT pressure cycling attempts. The port was sat to 4,500 psi and finally opened at 7,474 psi.
Fig. 14. Treatment chart for Well-B: Frac pumps attempted five times to open the HFS-B by bullheading. On the fifth attempt, it was opened at 8,000 psi and 4 bpm.
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Fig. 15. Pressure drop seen on first well during injection test within water.
Fig. 16. Pressure drop seen on second well during main treatment.
On all Supplier A jobs, the HFS has opened immediately as
planned, except on one well where barite mud was used for the
first time. It was concluded that barite should never be used
again due to the potential problems of mud particulates plugging the wellbore pores and preventing injectivity into the
reservoir rock. Despite the mud issues, the HFS-A on that one
well still opened after a short period of pressure cycling.
COMPARISON OF UNBALANCED AND BALANCED
LOWER COMPLETIONS
In two key wells, large pressure drops were seen when pumping into the first stage. In the first well, a drop was seen during
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the first injection step rate test (SRT), from 10,100 psi to
8,400 psi, Fig. 15. In the second well, a similar drop in surface
pressure was observed following spotting acid/mutual acid
during the main treatment; here there was a drop of 5,254 psi
surface pressure from an initial 10,800 psi, Fig. 16.
When pumping commenced into the second stage for both
wells, it was very clear that there was communication between
zones and that the packers were likely no longer holding pressure. As seen in Figs. 17 and 18, there was an immediate pressure decline to 0 psi surface pressure when the pumping was
stopped.
For the two initial gas well completion operations in 2007,
the open hole multistage systems were all in a balanced config-
62884araD5R1_ASC026 3/15/13 11:29 PM Page 6
Fig. 17. Communication between Stages 1 and 2 on first well.
Fig. 18. Communication between Stages 1 and 2 on second well.
uration. Due to the aforementioned mechanical and/or differential sticking issues during deployment, where the completion
was unable to reach the target depth, it was decided that an
unbalanced system was preferred. The theory was that if the
lower multistage completion was unable to reach target depth,
then the toe section of the well could still be treated.
One important consideration is that the open hole swell
packers or mechanical packers offer near negligible anchoring
capability. Testing performed in open hole conditions has
shown that it is possible to piston the packer uphole with certain overpull, depending on various downhole conditions.
Given the open hole diameter and the high pressures involved
during the stimulation treatments, the upward forces created
that are acting on the lowermost packer are very high: up to
400,000 lb upward force on the lower packer, Figs. 19 and 20.
With an unbalanced system and with high forces acting on the
bottom packer, the completion will undergo a rapid upwards
pistoning effect, and all of the lower completion will stroke a
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Therefore, as shown in Table 1, the upward movement of
the lowest open hole packer can be as much as 15 ft. When the
pressure is released, the completion will slide back towards its
original position. With every pressure cycle on this lowest
zone, the upward force will be created again, resulting in compression of the liner. The implication is that with a set packer
sliding along the open hole rock face several times during the
pressure cycles, it would be highly likely that the packer seals
would be damaged and thereby reduce its sealing ability, resulting in communication between zones. Initially, this would
be between Zones 1 and 2, but subsequent zones would also
be involved as with movement of the entire completion, all
open hole packer seals would very likely be damaged.
Fig. 19. Area (shaded in yellow) where the force is applied to the lowermost open
hole packer.
CARBONATE AND SANDSTONE COMPLETION
CONFIGURATIONS
Fig. 20. Diagram showing the calculated forces acting on the lower open hole
packer during the Stage 1 treatment in an unbalanced system.
significant distance uphole. This phenomenon is well proven
and simply related to the forces resulting from the pressures.
For example, with an unbalanced system inside an 8⅜”
hole, the piston area trying to push the packers up the hole is
37.742”, resulting in an upwards force of 377,400 lb with
10,000 psi differential pressure applied. In this case, the tubing
shrinkage increases the force by approximately another 50,000
lb; therefore the total upwards force is ~420,000 lb.
For a balanced system inside an 8⅜” hole, the piston area
trying to push the packers apart is 55.092”, so with 10,000 psi
differential pressure applied, there is over 550,000 lb of force
trying to part the tubing. This is counteracted somewhat by
tubing shrinkage due to the temperature drop, reducing the
force down to ~500,000 lb.
In a 5⅞” hole, the numbers are 27.112” for a balanced system and 17.492” for an unbalanced system, equaling 270,000
lb (220,000 lb with shrinkage) and 175,000 lb (225,000 lb
with shrinkage), respectively.
For all formation types, a balanced system would be the preferred method of running the multistage fracturing completion.
This is simply because the first stage is in a balanced condition,
and the forces created during the fracturing treatment are
equally applied, in opposing directions, to each packer. For
carbonate formations, the need for a balanced system is greatly
increased because with an unbalanced system the potential risk
of the acid treatment eroding away the formation around the
open hole packer is higher than in sandstone formations.
ADDITIONAL RECOMMENDATIONS FOR FUTURE
MULTISTAGE STIMULATION OPERATIONS
Due to improved operational running procedures and the use
of centralization of the liner, almost all of the recent systems
have reached target depth without issue1.
The recommendation for forthcoming wells has been to
standardize operations based on balanced systems. The idea
behind the design is to run a balanced multistage stimulation
completion with a single joint above the circulation valve assembly (with float collars and guide shoe). Above the lowest
Well Name
Open Hole
Size
Completion
Size OD
Completion
Size ID
Open Hole
Annulus Area
(sq. in)
Bottom-hole
Pressure (psi)
Reservoir
Pressure (psi)
Well-A
38
8½”
5½”
4.7”
37.74”
16,200
6,600
Well-B
78
5½”
4½”
3.813”
17.49”
13,500
5,200
Differential
Pressure (psi)
Force Created
on Lowest
Packer (lbsf)
Shrinkage due
to Temperature
Difference
(lbsf)
Resulting
Upwards Force
Created (lbsf)
Friction Forces
based on T&D
Analysis (lbsf)
Completion
Length (ft)
Resulting Liner
Movement (ft)
Uphole from
TD
9,600
362,304
50,000
412,304
80,000
3,760
8 ft
8,300
145,164
50,000
195,164
60,000
5,284
12 ft
Table 1. Liner upward movement resulting from applied forces on the lower packer when treating Stage 1 for an unbalanced system
36
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packer will be the first stage hydraulic. In this way, all
forces/movement will be balanced, and the open hole anchor
packer will be well set with a reduced chance of erosion from the
acid treatment. Second, as an added precaution to eliminate any
communication seen between Stage 1 and Stage 2, it is recommended to place an extra open hole packer between the stages.
CONCLUSIONS
This investigation is part of a more detailed report currently
being complied of evaluations performed on the multistage
stimulation fracturing and completion efficiencies. High rate
and high-pressure acid fracturing treatments have pushed the
completion equipment to its limits, and there is much still to be
learned on the interaction with carbonate formations. The well
direction and resulting fracture orientation is certainly a major
influence on the fluid placement. This investigation focused
solely on the completion equipment set-up and configurations.
The completion that was run on the second well by Supplier
B was an unbalanced system, and the completion was only anchored at the top of the liner by the liner hanger. The lowest
single sealing packer therefore began to slide immediately
when pressure was applied to it. A major pressure drop of approximately 1,700 psi was seen immediately during the SRT
when pumping water at approximately 8,300 psi differential
pressure (surface pressure less than reservoir pressure).
With 8,300 psi differential pressure and 145,164 lb of force
applied to the lowest packer in the 5⅞” open hole, with 5,284
ft of liner in total, the upwards movement can be as much as
12 ft. This would potentially damage the packer seal and
therefore allow communication between zones.
The completion used on the first well saw a pressure drop
occur following three days of pumping, which included an acid
treatment designed to dissolve some of the barite mud away.
Stage 1 of the completion system had been pressure cycled
many times up to its maximum differential of 9,600 psi by the
time the pressure drop was observed.
As a result of the deployment issues that led to a failure to
reach the target depths and the port opening problems, Supplier C was placed on hold from future operations in February
2011 and has not resumed multistage stimulation operations.
As a result of the hydraulic P-sleeve problems as well as CT
mill-out problems, Supplier B was placed on hold from future
operations in March 2011 and has yet to resume multistage
stimulation operations.
For future wells, it is recommended to run a balanced system with an open hole packer at the bottom of the first stage
prior to the hydraulic fracturing sleeve.
ACKNOWLEDGMENTS
for the permission to present and publish this article. Further
thanks are provided to the Saudi Aramco Multistage Fracturing
Team and the field crew for their outstanding work.
This article was presented at the International Petroleum
Technology Conference, Beijing, China, March 26-28, 2013.
REFERENCE
1. Al-Jubran, H.H., 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.
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 upstream projects, including pressure
control valve optimization, cathodic protection system
performance, venturi meter calibration, new stimulation
technologies, innovative wireline technology applications,
upgrading 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. During his tenure as HSE Advisor, he
founded the People-Oriented HSE culture, which has
brought impressive benefits to Saudi Arabia gas fields,
resulting in improved operational performance.
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 remote areas.
As a Production Engineer, Mohammed played a critical
role in the first successful application of several high-end
technologies to present new possibilities in the Kingdom’s
gas reservoirs.
Mohammed’s areas of interest include formation
damage investigation and mitigation, coiled tubing
applications, wireline operations, matrix acidizing,
hydraulic fracturing and organizational HSE performance.
In 2010, Mohammed received his B.S. degree with
honors in Petroleum Engineering from King Fahd
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 on the
industry and student advisory board in the Petroleum
Engineering Department of KFUPM from 2009 to 2011.
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62884araD5R1_ASC026 3/15/13 11:29 PM Page 9
Saad M. Al-Driweesh is a General
Supervisor in the Southern Area
Production Engineering Department
(SAPED), where he is involved in gas
production engineering, well
completion and fracturing and
stimulation activities. His main interest
is in the field of production engineering, including
production optimization, fracturing and stimulation, and
new well completion applications. Saad has 24 years of
experience in areas related to gas and oil production
engineering.
In 1988, he received his B.S. degree in Petroleum
Engineering from King Fahd University of Petroleum and
Minerals (KFUPM), Dhahran, Saudi Arabia.
Fadel A. Al-Ghurairi is a Petroleum
Engineering Consultant and Technical
Support Unit Supervisor working on
gas fields. He has 24 of years of
experience in production and reservoir
engineering. In the last 12 years, Fadel
has specialized in stimulation and
fracturing of deep gas wells.
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SPRING 2013
Abdulaziz M. Al-Sagr is a Supervisor
in the Southern Area Production
Engineering Department (SAPED). He
has been very involved in the gas
development program in the Southern
Area to meet the growing global gas
demand. Abdulaziz’s experience covers
several aspects of production optimization, including acid
stimulation, coiled tubing applications and fishing
operations.
In 1995, he received his B.S. degree in Chemical
Mustafa R. Al-Zaid is a Gas
Production Engineer at Saudi Aramco
working for the Southern Area
Production Engineering Department
(SAPED).
In 2010, he received his B.S. degree
in Petroleum Engineering from the
University of Adelaide, Adelaide, Australia.
62884araD6R1_ASC026 3/15/13 11:33 PM Page 1
An Iterative Solution to Compute Critical
Velocity and Rate Required to Unload
Condensate-Rich Saudi Arabian Gas Fields and
Maintain Field Potential and Optimal Production
Authors: Hamza Al-Jamaan, Dr. Zillur Rahim, Bandar H. Al-Malki and Adnan A. Al-Kanaan
ABSTRACT
INTRODUCTION
Saudi Arabian nonassociated gas reservoirs produce various
amounts of condensate depending upon field and reservoir
conditions. In most cases, these wells are hydraulically fractured, and at the initial stage after such stimulation treatment,
each well needs to unload a large quantity of the pumped fluid
to ensure the well’s full potential. If the liquid starts accumulating in the wellbore during production, the well productivity
will gradually decrease, and the well eventually may stop producing. If the gas flow velocity in the production string is high
enough, the gas will continue flowing and carry the liquid
droplets up the wellbore to the surface. The minimum velocity
and critical gas rate (Qcrit) are therefore the determining factors to ensuring the stable field production rate and maintaining the production plateau while producing a well or several
wells from a condensate-rich field.
An analytical model has been developed to iteratively compute the critical velocity (Vcrit) and Qcrit for a given flowing
wellhead pressure (FWHP), tubing diameter, and many other
reservoir and completion properties. If the FWHP is set and a
certain production rate is expected of a well, the program
automatically computes the pressure drop due to friction,
dynamic hydrostatic head and bottom-hole pressure (BHP).
Simultaneously, both the Vcrit and Qcrit required to unload the
fluids are calculated. If the Qcrit is above the expected production rate, a different wellbore completion is automatically
selected, and computation is continued until the Qcrit is lower
than the expected rate of the well. If this is not possible, the
program will display an appropriate message.
Several wells were analyzed from a condensate gas reservoir
in a field that has to maintain certain production potential for
a given number of years. The analyses show that the wells that
are producing without intervention are those that are confirmed by this model to be flowing above the Qcrit, and that
the wells that were intermittently producing and ultimately
could not sustain production were producing at rates below
the critical values. Using this iterative model, those rates can be
automatically adjusted for intermittent producers or a new
completion string will be suggested to bring them back into
production.
Liquid loading in gas reservoirs is a very important aspect to
consider when the goal is maintaining the production rate of a
field. Many gas reservoirs produce some amount of liquid in
association with the gas, either a hydrocarbon phase known as
condensate or an aqueous phase known as formation brine. If
this liquid accumulates in the wellbore, it will impair well productivity. The productivity can be restored if proper remedial
action is taken on the well. Figure 1 illustrates how the liquid
loading can drastically decrease the well rate until a proper
well intervention is implemented.
Liquid loading mainly occurs in low energy formations
(with low reservoir pressure) and in tight gas regions. This
problem can also occur in moderate to high permeability reservoirs with a high condensate to gas ratio (CGR).
For some wells, the liquid exists as a mist of droplets in the
produced gas. If the gas flow velocity in the production tubing
is high enough, the gas will carry the droplets up the wellbore
to be co-produced with the gas. The minimum gas velocity satisfying this condition is the Qcrit1, which is a function of rate
and is therefore related to the flowing wellhead pressure
(FWHP)2. As the FWHP increases, both gas rate and velocity
decrease. If a well’s production rate falls below the Qcrit, liquid
starts accumulating in the wellbore, which not only decreases
the production capacity of the well, but also adds to the back
Fig. 1. Well intervention is essential to restore production.
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62884araD6R1_ASC026 3/15/13 11:33 PM Page 2
diameter and BHP to find the optimal conditions for flowing
the well without causing any liquid holdup.
pressure on the reservoir and can eventually completely kill the
well. All gas wells go through a natural decline that can be
modeled accurately. It is only during the liquid loading that the
decline curve deviates. The curve can then be restored to its
original position by proper intervention on the well.
Early detection of liquid loading is essential to overcome
productivity decreases. Fluctuations in the daily gas rates and
casing pressures are characteristic of liquid accumulation in
gas wells. Determination of a fluid gradient in the tubing and
regular bottom-hole pressure (BHP) surveys can also indicate
liquid loading.
For proper reservoir management, it is imperative that each
well be closely followed to ensure that no fluid is building up
in the wellbore. This requires a good understanding and monitoring of the field, reservoir conditions, hydrocarbon properties, and the production and facility requirements and
constraints. Intense reservoir management and engineering
must be conducted so that a remedy can be quickly considered
if liquid buildup starts impairing well productivity.
One of the easier methods used to overcome liquid loading
is to produce the problem well intermittently. This involves
sustaining the natural flow of the well by alternatively shutting
in and opening the well. During the shut-in period, energy
gathers near the wellbore and then helps to unload the liquid
as the well is opened. The downside of this approach is that
the production from the well may be lost for several days or
weeks depending on how quickly the near wellbore pressure
builds up. This solution is also temporary as, with the depletion of the reservoir, the well will eventually stop producing.
The iterative software model developed in this study is an
excellent reservoir management tool that accurately computes
the Qcrit of a gas well, taking into consideration all the important reservoir and well properties. The model then provides
remedial actions for wells that flow below the Qcrit.
These remedial actions can include changing the tubing size
through a workover or decreasing the FWHP. A viable artificial lift method is also sometimes used through the implementation of a free piston or plunger to lift fluids to the surface
using the energy stored in the gas — the installation of
plungers reduces the problem faced with the intermittent production strategy. When liquid accumulation is considered and
acted upon, the intervention will restore well productivity and
maintain the overall field production rate.
As shown in Fig. 2, the flow regime that is desirable in gas
wells is the “mist flow,” where there is a continuous gas phase
with evenly dispersed liquid droplets. When a gas well flows
below the critical gas flow rate, the flow regime changes to
“slug flow,” where the liquid starts accumulating in the wellbore.
DESCRIPTION OF THE ITERATIVE MODEL
Procedure
The purpose of this software application is to calculate the
Qcrit for any given gas well utilizing the “Turner Droplet
Model” to ensure stable flow conditions. From certain input
values for a specific gas well, the program will calculate the
Qcrit and will test whether the well is flowing below or above
the Qcrit, which determines whether it is a candidate for intervention or not. The program will also test and plot how the
Qcrit for that specific well will vary with changes in tubing
To predict liquid loading in gas wells, the Turner Droplet
Model is used to calculate the critical gas velocity3 using the
following equation:
1
V
= 1.92 [σ (ți _țg)] ⁄4
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SPRING 2013 SAUDI ARAMCO JOURNAL OF TECHNOLOGY
Benefits
The iterative program has several benefits that make significant contributions to the management of a gas condensate
reservoir. The program is a quick guide to the stable flow conditions needed for gas wells to avoid possible accumulation of
liquids in the tubing. This model then provides proactive solutions to maintain continuous gas production. The model also
recognizes and predicts liquid loading that can happen in the
future, and simultaneously provides practical remedial action
to be taken at the outset to overcome later production impairment. By preventing liquid loading, it enhances the production
life of a gas condensate reservoir and ensures the most efficient
reserves exploitation.
Signs of Liquid Loading
Liquid loading is not easily identified. Even when a well is liquid loaded, it may continue to produce for a long time. It follows that if liquid loading is recognized and reduced at an
early stage, higher producing rates can be achieved and maintained. Symptoms indicating liquid loading include the following2:
• Pressure Gradient: Pressure surveys reveal a heavier
gradient.
• Variance from the Decline Curve: Typically gas wells
will follow an exponential-type curve decline; however,
liquid loading generally leads to a deviation from the
curve with a lower than predicted production rate.
• Liquid Slugging: Liquid production does not arrive to
the surface in a steady continuous flow, but instead in
slugs of fluid. This is readily observed through
production monitoring.
Crit-T
–––––––––––––————————————
țg1⁄2
where VCrit-T is the Turner critical velocity in feet/second, is the
gas-liquid interfacial tension in dyne/cm (dynes/centimeter), ți
62884araD6R1_ASC026 3/15/13 11:33 PM Page 3
Parameters
Units
Gas Rate
MMscfd
FWHP
psia
Condensate-to-Gas Ratio (CGR)
bbl/MMscfd
Average Wellbore Gradient
psi/ft
Reservoir Depth
ft
Gas Gravity (Air=1)
Liquid Density
kg/m3
Gas-Liquid Interfacial Tension
dynes/cm
Tubing Diameter
inches
Average Reservoir Pressure
psia
Bottom-hole Temperature
°F
Minimum Operating FWHP
psi
Table 1. Model input parameters
Fig. 2. Flow regime at different conditions.
is the liquid density in lb/ft3 (pounds/cubic foot), and țg is the
gas density in lb/ft3. In this equation, the gas density is approximated at the bottom-hole conditions, and the BHP is calculated from the FWHP using Guo’s analytical method4. The
critical flow rate is subsequently computed and converted to
standard conditions using the following formula:
Qcrit =Vcrit-T x ATubing.
At standard conditions of 60 °F and 14.6 psi, the molar volume is 379.48 ft3/lb-mol. To perform this computation and
conduct a sensitivity analysis, the data provided in Table 1 is
input in the program.
Based on this input, the program will calculate the critical
gas flow rate and simultaneously assess whether the well is
flowing above or below that critical rate. The program will
also output a plot showing how the critical gas flow rate varies
with tubing diameter and flowing bottom-hole pressure
(FBHP). If the well is flowing below the Qcrit, several interventions are automatically presented for consideration to fix the
problem. These include:
• Reduction of FBHP, subject to constraints imposed by
reservoir engineering.
• Use of minimum operating FWHP input by the user.
Reducing the FBHP will affect the situation in two ways: it
will decrease the density of the gas in the tubing and will increase the production rate from the formation into the tubing.
2
The gas well production rate is defined as Q = C (Pr2 –Pwf
)n,
where C is a constant that includes drainage radius, radius of
the wellbore, formation thickness, reservoir permeability, reservoir temperature, gas compressibility, etc., and n accounts for
non-ideal gas behavior. It is assumed that the C and n values of
the well do not change when the FBHP is reduced. The variable Pr in this equation is the average reservoir pressure (psia),
Pwf is the FBHP (psia), Q is the gas rate (Mscfd), the value of n
ranges from 0.5 to 1, and C is defined by Mscfd/psia2.
The user can also evaluate the effect of replacing the tubing
with the next smaller size (velocity string concept) and the
effect of reducing the gas-liquid interfacial tension (soap-sticks
concept). The following sections present a few examples where
gas condensate wells were analyzed using the iterative program.
EXAMPLE WELL-1
Figure 3 presents the well parameters and reservoir conditions
that were input for the well. They show that the well is flowing at
a low rate of 1 million standard cubic ft per day (MMscfd), and
the condensate yield is 130 bbl/MMscf. From a reservoir pressure
of 4,000 psi and a reservoir temperature of 240 °F, the program
computed a critical gas rate of 4.18 MMscfd for this well.
The result box provided at the bottom of Fig. 3 shows that
the current well production rate (1 MMscfd) is lower than the
critical gas flow rate, and therefore the well is loading up with
liquids. An intervention box thereby appeared to suggest a reduction in the tubing size to overcome the slug flow. At the
current well flowing conductions and based on the inflow performance curve that the program automatically computes, the
BHP is also low. Therefore, the only possible solution for getting the well to produce above the critical gas flow rate is to
reduce the tubing size, which is also aligned with the velocity
string concept that reduces the flow area of a well by inserting
an external string in the wellbore.
After clicking the “show intervention” button marked in
green, Fig. 3, a plot of Qcrit vs. tubing internal diameter
appeared, Fig. 4.
SPRING 2013
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62884araD6R1_ASC026 3/15/13 11:33 PM Page 4
Fig. 3. Well-1 input variables.
Fig. 5. Well-2 input variables.
Fig. 4. Critical gas flow rate vs. tubing internal diameter plot for Well-1.
Fig. 6. Critical gas flow rate vs. tubing internal diameter plot for Well-2.
The iterative software application in this example has computed the following:
prevent slug flow. Reducing the tubing size will result in a
lower critical gas flow rate. If the FBHP is reduced, the critical
gas flow rate also decreases; this is because the gas density in
the tubing will decrease as a result of the FBHP reduction and
will thereby increase the production rate from the formation
into the tubing. In the case of Well-1, the FBHP was already
low, and further reduction of the FBHP was not possible due
to the constraint imposed by the engineer (a minimum operating FWHP of 1,000 psia). The only possible solution in this
case was to reduce the tubing size.
• The critical gas flow rate for the initial conditions.
• A plot showing the effect on the critical gas flow rate of
reducing the tubing internal diameter and FBHP.
If intervention is needed, the program will calculate the
optimal gas rate that can be achieved by reducing the FBHP,
based on a minimum operating FWHP input by the user
(1,000 psia), and will inform the user whether the test was
successful or not. In all cases, if a well is flowing below the
critical gas flow rate, then intervention is always required to
42
62884araD6R1_ASC026 3/15/13 11:33 PM Page 5
Fig. 7. Critical gas flow rate vs. FBHP.
Fig. 9. Critical gas flow rate as a function of hydrocarbon density.
Fig. 10. Effects of CGR on well performance.
Fig. 8. Critical gas flow rate as a function of FWHP and CGR.
EXAMPLE WELL-2
The input variables in Fig. 5 show that, for the given reservoir
properties, the Qcrit for Well-2 is 5.75 MMscfd. This well was
currently producing at 10 MMscfd, which is above the critical
gas rate, so no intervention was required.
It is also worth noting that plots of Qcrit vs. tubing internal
diameter and FBHP, Fig. 6, were still generated so users can
better understand how these critical rates change throughout
the life of the well as reservoir pressure depletes. Also, in case a
tubing replacement is required for this well due to corrosion or
damage, an assessment of the effect of the new tubing size on
the production rate can be quickly performed.
The critical gas rate for Well-2 is higher than that for Well1. That is because certain factors, such as tubing diameter and
BHP, have a significant impact on the Vcrit calculation compared to gas gravity, interfacial tension and bottom-hole temperature. Well-2 has a much higher BHP than Well-1, resulting
in higher gas density and a higher Vcrit. The Qcrit vs. the FBHP
plot is provided in Fig. 7.
Example Sensitivity Runs
Qcrit is a function of many parameters, such as reservoir and
well configuration.
Fig. 11. Declining gas rate with higher CGR and lower reservoir pressure.
A sensitivity example presented in Fig. 8 shows the impact
of FWHP and tubing size on the Qcrit. A decrease in FWHP
and tubing size means a lower flow rate is required to keep a
well continuously unloaded. The figure also illustrates that an
increase in CGR increases the Qcrit and that the proportion
depends on hydrocarbon properties and well configuration.
Figure 9 shows the Qcrit as a function of hydrocarbon density
for a well with CGR = 100 bbl/MMscfd.
Figure 10 illustrates the effects of CGR and reservoir pressure on gas well performance. The CGR value has been varied
between 10 and 500 bbl/MMscfd for reservoir pressures between 5,000 psi and 8,000 psi, respectively. The FWHP was
held constant at 3,000 psi. Figures 11 and 12 illustrate gas rates
and changing gas density as a function of CGR and reservoir
SPRING 2013
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62884araD6R1_ASC026 3/15/13 11:33 PM Page 6
International Petroleum Exhibition and Conference, Abu
Dhabi, U.A.E., November 1-4, 2010.
2. Lea, J.F. and Nickens, H.V.: “Solving Gas Well LiquidLoading Problems,” Journal of Petroleum Technology, Vol.
56, No. 4, April 2004, pp. 30-36.
3. Turner, R.G., Hubbard, M.G. and Dukler, A.E.: “Analysis
and Prediction of Minimum Flow Rate for the Continuous
Removal of Liquids from Gas Wells,” Journal of Petroleum
Technology, Vol. 21, No. 11, November 1969, pp. 1,4751,482.
Fig. 12. Gas density as a function of reservoir pressure.
pressure. It is noted that in low-pressure reservoirs (depleted
reservoirs) some of the high CGR wells will not produce. A
remedial plan therefore needs to be considered in advance to
overcome such situations.
CONCLUSION
Liquid loading is a complex phenomenon, and accurately modeling the process is very difficult due to the various flow regimes and
the dynamics of fluid flow and its interaction among reservoir,
wellbore and surface hydraulics. Most models are based on
steady-state flow solutions and therefore cannot necessarily
capture the full process that occurs throughout the life of a well.
Liquid loading is currently one of the major challenges
faced in high CGR fields, and several wells have been shut-in
due to the inability to unload fluids accumulated in their wellbores. If the Qcrit is calculated and predicted earlier, then steps
can be taken to maintain the well rate above the Qcrit to avoid
liquid loading. The software application developed in this
study detects the loading process and automatically generates a
solution so that well intervention can be planned in advance.
This application was initially developed and coded in visual
BASIC and was then transferred into an easier and more userfriendly interface to better conduct the runs and sensitivity
analysis. Several wells have been analyzed using this model,
which has greatly helped in improving good reservoir management practices.
ACKNOWLEDGMENTS
This article was presented at the SPE Kuwait International
Petroleum Conference and Exhibition, Kuwait City, December
10-12, 2012.
REFERENCES
1. Hearn, W.: “Gas Well Deliquification Application
Overview,” SPE paper 138672, presented at the
44
4. Guo, B.: “Use of Wellhead Pressure Data to Establish Well
Inflow Performance Relationship,” SPE paper 72372,
presented at the SPE Eastern Regional Meeting, Canton,
Ohio, October 17-19, 2001.
BIOGRAPHIES
Hamza Al-Jamaan is a Petroleum
Engineer with the Gas Reservoir
Management Department at Saudi
Aramco. His interests include general
reservoir engineering, field
development and production
optimization. Currently, Hamza is
pursuing his M.S. and Ph.D. degrees in Petroleum
Engineering at Stanford University, Stanford, CA. His
current research involves the characterization and
petrophysics of shale gas.
He received a dual B.S. degree with honors in Petroleum
Engineering and Economics from the University of Texas at
Austin, Austin, TX.
Dr. Zillur Rahim is a Petroleum
Engineering Consultant with Saudi
Aramco’s Gas Reservoir Management
Department (GRMD). He heads the
team responsible for stimulation
design, application and assessment for
GRMD. Rahim’s expertise includes
well stimulation, pressure transient test analysis, gas field
development, planning, production enhancement, and
reservoir management. Prior to joining Saudi Aramco, he
worked as a Senior Reservoir Engineer with Holditch &
Associates, Inc., and later with Schlumberger Reservoir
Technologies in College Station, TX, where he used to
consult on reservoir engineering, well stimulation, reservoir
simulation, and tight gas qualification for national and
international companies. Rahim is an Instructor of
petroleum engineering industry courses and has trained
engineers from the U.S. and overseas. He developed
analytical and numerical models to history match and
forecast production and pressure behavior in gas reservoirs.
Rahim developed 3D hydraulic fracture propagation and
proppant transport simulators and numerical models to
compute acid reaction, penetration, and fracture
62884araD6R1_ASC026 3/15/13 11:33 PM Page 7
conductivity during matrix acid and acid fracturing
treatments.
Rahim has authored 65 Society of Petroleum Engineers
(SPE) papers and numerous in-house technical documents.
He is a member of SPE and a technical editor for the
Journal of Petroleum Science and Engineering (JPSE).
Rahim is a registered Professional Engineer in the State of
Texas and a mentor for Saudi Aramco’s Technologist
Development Program (TDP). He is an instructor of the
Reservoir Stimulation and Hydraulic Fracturing course for
the Upstream Professional Development Center (UPDC) of
Saudi Aramco. Rahim is a member of GRMD’s technical
committee responsible for the assessment and approval of
new technologies.
Rahim received his B.S. degree from the Institut Algerien
du Petrole, Boumerdes, Algeria, and his M.S. and Ph.D.
degrees from Texas A&M University, College Station, TX,
all in Petroleum Engineering.
Bandar H. Al-Malki joined Saudi
Aramco in 1998 as a Production
Engineer, working in the company’s
gas fields. He is currently the General
Supervisor of the Gas Reservoir
Management Division. This role
requires him to monitor the
production capacity of the plants, while optimizing the
productivity of the wells and preventing wasted time and
resources.
Bandar received his B.S. degree in Petroleum
Minerals (KFUPM), Dhahran, Saudi Arabia. In 2004, he
earned his M.S. degree in Petroleum Engineering from the
Imperial College, London, U.K., focusing on gas
condensate reservoirs.
Adnan A. Al-Kanaan is the Manager
of the Gas Reservoir Management
Kingdom to meet its ever increasing energy demand. He oversees the operating and business plans of GRMD, new
technologies and initiatives, unconventional gas development
programs, and the overall work, planning and decisions
made by his more than 70 engineers and technologists.
Supervisor for the Gas Reservoir Management Division under
the Southern Reservoir Management Department for 3 years,
heading one of the most challenging programs in optimizing
and managing nonassociated gas fields in Saudi Aramco.
Adnan started his career at the Saudi Shell Petrochemical Company as a Senior Process Engineer. He then
joined Saudi Aramco in 1997 and was an integral part of
the technical team responsible for the on-time initiation of
the two major Hawiyah and Haradh Gas Plants that
currently process more than 6 billion cubic feet (bcf) of gas
per day. Adnan also directly managed the Karan and Wasit
fields — two major offshore gas increment projects — with an
expected total production capacity of 4.3 bcf of gas per day.
test analysis, simulation modeling, reservoir characterization,
hydraulic fracturing, reservoir development planning and
reservoir management.
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Microbial Community Structure in a Seawater
Flooding System in Saudi Arabia
Authors: Mohammed A. Al-Moniee, Dr. Indranil Chatterjee, Dr. Gerrit Voordouw, Dr. Peter F. Sanders and
Dr. Tony Y. Rizk
ABSTRACT
A pyrosequencing survey of planktonic seawater and sessile
pipeline solids samples from a seawater injection system in
Saudi Arabia indicates the presence of distinct microbial communities. The pipeline surface had a microbial community
consisting of the anaerobic heterotrophs Roseovarius, Ruegeria, Colwellia, Lutibacter and Psychrobacter, which ferment
refractory organic carbon to intermediates (e.g., lactate and
H2) and are then used by sulfate-reducing bacteria (SRB) of the
genus Desulfovibrio to reduce sulfate to sulfide. All of these
microbes were present in a much smaller fraction in the seawater, e.g., Desulfovibrio was present in a 100-fold smaller fraction in the planktonic seawater population than in the pipeline
solids. The presence of sulfur in the pipeline solids, as determined by X-ray powder diffraction (XRD), and of high numbers of cultivatable SRB (108/g) also indicated the potential for
significant microbially influenced corrosion (MIC) risk, biofouling and water quality deterioration. The data suggests that
measures to control SRB should be continued and possibly
adjusted to decrease the risk of operational problems caused
by SRB growth and activity.
INTRODUCTION
In water injection, or waterflooding, either aquifer water or
deoxygenated and filtered seawater is injected at strategic
points along the periphery of the oil reservoir, displacing the
oil and “pushing” it towards oil supply wells in the center of
the formation. The technique increases crude oil recovery
substantially and allows for greater returns from the field.
Nonpotable water from underground aquifers located
above the oil reservoirs is usually used in injection programs to
maintain reservoir pressure. Oil companies also have converted
some of their water injection facilities to use treated seawater
in waterflooding to conserve the aquifers for future use.
The seawater injection system studied uses water from a
seawater treatment plant in Saudi Arabia that treats millions of
gallons of seawater per day from the Gulf region and ships it
over very long distances (hundreds of kilometers) through
massive transfer lines. Given the size and complexity of the
injection system and the high salinity of the water it uses
46
(~55,000 mg/l); microbial content present throughout the system differs from one location to another due to exploitation of
the biocide batch treatment further downstream of the system.
Moreover, produced water re-injection may enrich microbial
content and may allow different microbial species to live on
the higher concentration of organics in some parts of the system.
The waterflooding system in Saudi Arabia was subjected to
a microbial community structure review. Conventional microbial investigations were conducted to assess the microbial activity in the system. The progress in molecular biology and
DNA sequencing technologies has opened endless possibilities
to analyze microbial communities and identify the types of microorganisms responsible for relevant microbial activities, such
as souring and corrosion. Pyrosequencing, a massive parallel
DNA sequencing technology, was used here to characterize the
community composition of the seawater injection system.
MATERIALS AND METHODS
Sample Description and Preparation
Two samples of scraping solids (Table 1, Samples 5 and 6)
were collected from a water pump station in the system and
analyzed using environmental scanning electron microscopy
(ESEM) coupled with an energy dispersive X-ray spectroscopy
(EDS) analyzer to assess the presence of sulfate-reducing bacteria (SRB) in the system.
Four seawater samples from the system (Table 1, Samples 1
to 4) were collected from various locations in the field and analyzed using the 16S pyrosequencing method to assess the microbial community composition in the system. The seawater
samples were filtered on-site at the field locations where the
samples were collected, using 0.2 µm filters. The filters were
fixed and dried. Each of the six samples (the scraping solids
and the water samples) were transferred into 2 ml Eppendorf
tubes and sent to the University of Calgary for DNA extraction
and pyrosequencing analysis. Upon arrival at the laboratory,
the tubes were strongly vortexed with seawater filtrate to suspend the biomass. This was repeated two to three times to ensure that the greatest amount of biomass was recovered. Next,
the tubes were centrifuged at 17,000 x g for 10 minutes. The
supernatant was discarded and the cell pellet was frozen at -70
°C until DNA extraction.
62884araD7R1_ASC026 3/15/13 11:36 PM Page 2
Sample
Description
PCR Product
(ng/ml)
Sample #1
Injection well
45.8
Sample #2
Water 2
51
Sample #3
Water 3
41.9
Sample #4
Water 4
25.7
Sample #5
Scraping solids-1
48.9
Sample #6
Scraping solids-2
48.8
Table 1. Concentration of second PCR amplification products using Quant-iT
dsDNA HS assay kit
Fig. 1. Agarose (0.7%) gel analysis of first PCR amplification product. M = l
HindIII molecular marker. Samples 1 to 6 are as described in Table 1. -vecnt =
negative control without added DNA.
DNA Extraction Technique
The cell pellets stored at -70 °C were taken out and thawed to
room temperature. The cell pellets were re-suspended in 280 µl
of 0.15 M NaCl and 0.1 M ethylene diamine tetra-acetic acid
(pH 8). Genomic DNA was isolated using a procedure outlined
in Marmur1. In brief, the cell pellets were treated with
lysozyme (to weaken the bacterial cell wall), followed by treatment with 25% sodium dodecyl sulfate and then with three
rounds of freeze-thaw cycles (-70 °C to 68 °C).
Treatment with DNase-free RNase and recombinant Proteinase K (Roche Diagnostics, GmbH) was done to remove
RNA and protein contaminants, respectively. DNA was further
purified by precipitation with a DNA precipitation mix
(sodium acetate + ethanol) and by washing with 70% ethanol.
DNA was re-suspended in buffer EB (10 mM Tris-Cl, pH 8.5;
Qiagen QIAquick kit).
Community Structure Analysis by Pyrosequencing
DNA samples were amplified through a two-step polymerase
chain reaction (PCR) amplification. The first PCR (25 cycles)
was performed with 16S primers 926Fw (AAACTYAAAKGAATTGRCGG) and 1392R (ACGGGCGGTGTGTRC).
Agarose gel analysis confirmed the presence of the desired
PCR product at approximately 500 bp, Fig. 1.
Using this as the template, a second round of PCR (10 cycles)
was performed using the FLX Titanium Amplicon primers
454T_RA_X and 454T-FB. These have the sequences for 16S
primers 926Fw and 1392R as their 3 ft ends. Primer 454T_RA_X
has a 25 nucleotide A-adaptor (CGTATCGCCTCCCTCGCGCCATCAG) and a 10 nucleotide multiplex identifier
barcode sequence X, whereas primer 454T-FB has a 25 nucleotide B-adaptor sequence (CTATGCGCCTTGCCAGCCCGCTCAG). Following the second PCR amplification, the
PCR product was checked on a 0.7% agarose gel, Fig. 2, and
purified with a QIAquick PCR purification kit (Qiagen).
The second PCR product concentration, Table 1, was then
determined by a Qubit fluorometer (Invitrogen), using a
Quant-iT™ dsDNA high sensitivity (HS) assay kit (Invitrogen).
Fig. 2. Agarose (0.7%) gel analysis of second PCR amplification product. M = l
HindIII molecular marker. Samples 1 to 6 are as described in Table 1. -vecnt =
negative control without added DNA.
PCR products (typically 20 µl of 5 ng/µl) were sent for pyrosequencing analyses. Pyrosequencing was performed with a
Genome Sequencer FLX instrument, using a GSFLX Titanium
Series kit XLR70 (Roche Diagnostics Corporation).
RESULTS AND DISCUSSION
Initial Bacterial Assessment
Initial bacterial assessment of the scraping solids samples and
four seawater samples from different locations in the field confirmed the presence of SRB. The scraping solids contained a
high concentration of SRB, in the range of 108/g of scraping
solids. The ESEM and EDS results, Fig. 3, showed that the
main elements in the samples were sulfur, oxygen, sodium and
iron. The samples were rich in FeS (mackinawite) and NaCl.
The X-ray powder diffraction (XRD) method was also used to
determine the phase identification and quantification of the
scraping solids (one scraping solid and scraping filter). The results showed that the major phases are 55% magnetite [Fe3O4]
and 22% akaganeite [FeO(OH)] for the scraping solid, and
44% mascagnite [(NH4)2S] and 42% mackinawite [FeS] for
the scraping filter. A high amount of Fe (41%) as well as the
presence of sulfur (8%) was detected through an X-ray
fluorescence (XRF) elemental analysis on the scraping solid
SPRING 2013
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the Mothur software package5. The filtered sequences, after
passing the quality control process for problematic, chimerical
and eukaryotic sequence removal, were clustered into operational taxonomic units (OTUs) at 3% distance by using the
complete linkage algorithm in Mothur.
A taxonomic consensus of each representative sequence
from each OTU was derived from the recurring species within
5% of the best bit score from a BLAST search against the
SILVA database. Of the good reads generated by pyrosequencing, 36,138 were assigned taxonomic identifiers, which were
identified at the genus level.
Microbial Communities in the Injection System
Fig. 3. ESEM image at 1-2 µ and the corresponding EDS X-ray spot analysis
spectrum.
and indicated sulfate reduction in agreement with the high
numbers of SRB.
Pyrosequencing Data
The pyrosequencing data were analyzed by Phoenix-2, a bioinformatics pipeline developed in-house2. Sequence reads were
subjected to stringent systematic checks to remove low quality
reads and minimize sequencing errors that can be introduced
during the pyrosequencing process3. Eliminated sequences included those that: (1) did not perfectly match the adaptor and
primer sequences, (2) had ambiguous bases, (3) had an atypical length of 1 SD away from mean length after removing
adaptor and primer sequences, (4) had an average quality
score below 25, and (5) contained homopolymer lengths
greater than 8 bp.
The remaining high quality sequences were compared
against the nonredundant SSU reference data set of SILVA1024
using the Tera-BLAST algorithm on a TimeLogic decypher system from Active Motif, Inc., consisting of 12 boards. The
Tera-BLAST results were used to screen for problematic,
chimerical and eukaryotic sequences. Sequences having a best
alignment covering less than 70% or having a best BLAST
search hit an e-value greater than e-50 were excluded as problematic sequences.
Putative chimeras were identified by using a two-stage
approach. The sequences having a best alignment covering less
than 90% of the trimmed read length, with greater than 90%
sequence identity to the best BLAST match, were identified as
potential chimeras. The potential chimeras were excluded from
further analysis if they were also identified as chimeras at minimum 80% bootstrap support in chimera.slayer implemented in
48
Both planktonic seawater samples and sessile pipe samples
were analyzed. Table 2 and Fig. 4 show the percentage of reads
in each sample. This gives an indication of the microbial diversity in the samples. Bar diagrams, Fig. 4, were constructed using the average percentage of reads of each sample. It indicates
the main microbial population (genus level) in the seawater
samples. Some interesting differences among the samples are
apparent. For example, sample 2 has a high fraction of Polaromonas, which was not found in any other sample. In the
absence of information on what these samples represent, we
cannot make suggestions on why these microorganisms are
found at these particular sites.
The betaproteobacterium Delftia was found to be the most
prominent genus in the seawater samples (39%). Delftiatsuruhatensis, a terephthalate-assimilating bacterium, has been
isolated from activated sludge from a domestic wastewater
treatment plant in Japan6. In another recent study, Delftia spp.
were isolated as a novel peptidoglycan-degrading bacterium in
samples from mesotrophic lake water in Denmark7.
In addition to Delftia, the alphaproteobacterium Sphingomonas as well as the gammaproteobacteria Pseudomonas,
Pseudoalteromonas and Sedimenticola were also dominant in
seawater samples. Among these, Sedimenticola has been documented as an anaerobic selenate-respiring bacterium isolated
from estuarine sediment8. The well-known sulfate-reducing
deltaproteobacterium Desulfovibrio was present with an average fraction of 2.37%.
Fig. 4. Graphical representation of genus level survey of 16S sequences in the
seawater injection system. The average for all six samples (Table 2) is shown.
62884araD7R1_ASC026 3/15/13 11:36 PM Page 4
Number of Reads (n)
24,485
14,156
10,329
SA-1 to SA-6
SA-1 to SA-4
SA-5 to SA-6
Sample Type
All
Seawater
Srapings
Ratio
Average Reads
(%)
A1 (%)
A2 (%)
A2/A1
Betaproteobacteria Delftia
39.58
53.50
11.72
0.22
Alphaproteobacteria Sphingomonas
16.24
22.05
4.62
0.21
Saudi Aramco Sample Numbers
Class Genus
Gammaproteobacteria Pseudomonas
6.28
0.24
18.95
78.48
Gammaproteobacteria Pseudoalteromonas
4.89
7.33
0.02
0.00
Gammaproteobacteria Sedimenticola
2.56
0.18
7.32
39.78
Betaproteobacteria Polaromonas
2.50
3.75
0.00
0.00
Gammaproteobacteria Colwellia
2.47
0.15
7.11
47.40
Deltaproteobacteria Desulfovibrio
2.37
0.07
6.98
98.70
Betaproteobacteria Petrobacter
2.17
0.05
6.43
142.96
Flavobacteria Lutibacter
1.20
0.24
3.13
13.04
Gammaproteobacteria Thiomicrospira
1.15
0.19
3.07
16.57
Gammaproteobacteria Acinetobacter
1.03
0.93
1.25
1.35
Alphaproteobacteria Roseovarius
0.99
0.03
2.91
90.28
Deltaproteobacteria Desulfurivibrio
0.81
1.08
0.26
0.24
Alphaproteobacteria Bradyrhizobium
0.71
1.00
0.14
0.13
Actinobacteria Microbacterium
0.69
0.91
0.24
0.26
Gammaproteobacteria Psychrobacter
0.64
0.23
1.46
6.34
Betaproteobacteria Achromobacter
0.60
0.02
1.77
92.05
Betaproteobacteria Hylemonella
0.59
0.88
0.00
0.00
Alphaproteobacteria Ruegeria
0.57
0.18
1.33
7.35
Table 2. Genus level survey of 16S sequences in samples of seawater and scrapings listed in Table 1. The number of pyrosequencing reads (n) and the average fraction
(%) of these for each genus are indicated for the 20 most prevalent genera. The list is ranked in order of most to least prevalent genus (average for all samples).
Averages for seawater (A1) and scrapings (A2) samples are also provided, as well as the ratio R=A2/A1, which indicates prevalence in pipeline scrapings
Sessile Microbial Community
The data obtained allowed comparison of the planktonic community (Table 2, A1, the average for seawater samples 1 to 4)
and the sessile community present on the pipeline wall (Table 2,
A2, the average for scrapings samples 5 and 6). The ratio
R=A2/A1 was calculated for each entry in Table 2 and indicated
the tendency of a given microbe to attach to the pipeline wall.
The sessile community was dominated (in order of decreasing R) by Petrobacter, Desulfovibrio, Achromobacter, Roseovarius, Colwellia, Sedimenticola, Thiomicrospira, Lutibacter,
Ruegeria and Psychrobacter. Of these, Petrobacter and Achromobacter are potentially anaerobic heterotrophic bacteria, capable of degrading organic carbon in seawater. Roseovarius
and the related Ruegeria, Colwellia, Lutibacter and Psychrobacter are commonly isolated from seawater, with
Colwellia being capable of Fe-III reduction.
Collectively, these bacteria may form a biofilm on the
pipeline wall, anaerobically degrading organic carbon in seawater. Degradation products (e.g., lactate or H2) are then used
by SRB of the genus Desulfovibrio to reduce sulfate to sulfide.
Sulfide may be reoxidized by Thiomicrospira if traces of oxygen remain in the seawater.
CONCLUSIONS
Planktonic seawater and sessile pipeline solids samples (Samples 1 to 4 and Samples 5 and 6, respectively) from the seawater injection system in Saudi Arabia harbor a diverse microbial
community, which shows very significant differences, Table 2.
The pipeline surface has a microbial community with a 100fold higher fraction of SRB of the genus Desulfovibrio, which
may contribute to microbially influenced corrosion and biofouling. Therefore, treatment to limit pipeline damage, as currently being undertaken, must continue or must be adjusted to
prevent further proliferation of SRB.
ACKNOWLEDGMENTS
This work was supported by an NSERC Industrial Research
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Chair Award to GV, which was also supported by Baker
Hughes Inc., Commercial Microbiology Ltd. (Intertek), the
Computer Modeling Group Ltd., ConocoPhillips Company,
YPF SA, Aramco Services, Shell Canada Ltd., Suncor Energy
Developments Inc. and Yara International ASA, as well as by
the Alberta Innovates-Energy and Environment Solutions. The
work was also supported by funding from Genome Canada,
Genome Alberta, the Government of Alberta and Genome BC.
We thank Xiaoli Dong and Christoph Sensen for the bioinformatics analyses.
REFERENCES
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C.W., Caffrey, S.M., et al.: “Effect of Sodium Bisulfite
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Brackish Water Transporting Pipeline,” Applied and
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Welch, D.M.: “Accuracy and Quality of Massively Parallel
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July 20, 2007.
4. Pruesse, E., Quast, C., Knittel, K., Fuchs, B.M., Ludwig,
W., Peplies, J., et al.: “SILVA: A Comprehensive Online
Resource for Quality Checked and Aligned Ribosomal
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7,188-7,196.
5. Schloss, P.D., Westcott, S.L., Thomas, R., Hall, J.R.,
Hartmann, M., Hollister, E.B., et al.: “Introducing Mothur:
Open Source, Platform Independent, Community
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7,537-7,541.
6. Shigematsu, T., Yumihara, K., Ueda, Y., Numaguchi, M.,
Morimura, S. and Kida, K.: “Delftiatsuruhatensis sp. nov.,
a Terephthalate-assimilating Bacterium Isolated from
Activated Sludge,” International Journal of Systematic
Evolutionary Microbiology, Vol. 53, September 2003, pp.
1,479-1483.
7. Jørgensen, N.O.G., Brandt, K.K., Nybroe, O. and Hansen,
M.: “Delftialacustris sp. nov., a Peptidoglycan-degrading
Bacterium from Fresh Water, and Emended Description of
Delftiatsuruhatensis as a Peptidoglycan-degrading
Bacterium,” International Journal of Systematic
Evolutionary Microbiology, Vol. 59, 2009, pp. 2,1952,199.
50
8. Narasingarao, P. and Häggblom, M.M.: “Sedimenticola
selenatireducens, gen. nov., sp. nov., an Anaerobic Selenaterespiring Bacterium Isolated from Estuarine Sediment,”
Systematic and Applied Microbiology, Vol. 29, January 20,
2006, pp. 382-388.
BIOGRAPHIES
Mohammed A. Al-Moniee joined
Saudi Aramco’s Petroleum
Microbiology Unit of the Research &
Development Center (R&DC) in 1998.
He is currently working as a Senior
Lab Scientist with the Material
Performance Group of the Technical
Services Division, R&DC. In June 2005, Mohammed
undertook an internship program with the Biotechnology
Department at the Institute Francias du Petrol (IFP),
France, working on bio-denitrogenation of diesel oil. He
has over 15 years of professional and field experience in
the areas of microbial corrosion, bactericides and microbial
sensing, biofouling and bioprocessing for oil upgrading.
Mohammed has handled various projects covering Saudi
Aramco’s oil fields. In particular, he has worked on
bacterial monitoring and control in the seawater injection
system and oil pipeline system.
In 1997, Mohammed received his B.S. degree in
Chemistry from the University of Toledo, Toledo, OH, and
in 2012, he received his M.S. degree in Project
Management (Oil and Gas Specialty) from the University of
Liverpool, Liverpool, U.K.
Mohammed has authored or coauthored numerous
journal and international conference publications in his
areas of expertise. He is an active member of the American
Chemical Society (ACS) and the Saudi Arabian
International Chemical Science Chapter of ACS.
Dr. Indranil Chatterjee is the Senior
Research Microbiologist at the Pune
Technology Center, India, for the Oil
Field Chemical Division of Nalco (An
Ecolab Company). He acquired
experience in various microbiological
and molecular techniques in addition
to projects dealing with global genomic analysis
(transcriptomics and proteomics). In addition, Indranil was
also involved in pharmaceutical industrial projects with
Bayer Vital, GmbH and Wyeth Pharma, GmbH.
Following his 6 years of research experience with
Medical Microbiology, he joined the Petroleum Microbiology Research Group (PMGR) at the University of
Calgary, Calgary, Alberta, Canada. Here, Indranil was
assigned to a project funded by Genome Canada/Genome
Alberta, working as a senior postdoctoral fellow. During
this time, he was responsible for conducting research into
the composition of microbial communities within varied
hydrocarbon resource environments using modern
metagenomic tools and evaluating biotechnologies to
improve oil production. Indranil was involved in several
62884araD7R1_ASC026 3/15/13 11:36 PM Page 6
projects with oil and gas companies before joining the
Nalco Technology Center in 2011.
Indranil received his B.Pharm. degree from the
University of Pune, Pune, India, and his M.S. degree in
Molecular Genetics from the University of Leicester,
Leicester, U.K. Following this, he successfully completed his
Ph.D. degree with the dissertation “Senescence of
Staphylococci: Metabolic and Environmental Factors
Determining Bacterial Survival and Persistence” at the
Institute of Medical Microbiology and Hygiene, University
of Saarland-Hospital, Homburg, Germany. Indranil
followed this with an additional 3 years of postdoctoral
experience in medical and infectious microbiology.
He has published in several peer-reviewed journals in
the areas of both medical microbiology and petroleum
microbiology.
Dr. Gerrit Voordouw has been a
Professor of Microbiology in the
Department of Biological Sciences at
the University of Calgary since 1986
and has held the NSERC Industrial
Research Chair in Petroleum
Microbiology since 2007. As an
Industrial Research Chair holder, he works closely with
major energy companies to coordinate the research
activities in his lab focused on sulfur cycle management,
corrosion control and improved production. Gerrit served
as a member of the Technical Advisory Committee to the
Saudi Aramco Research & Development Center (R&DC)
from 2009 to 2011.
In addition to researching practical aspects of petroleum
microbiology, he is project leader of a 4-year Genome
Canada funded project, aimed at characterizing the
microbial communities in hydrocarbon resource
environments through state-of-the-art DNA sequencing
technologies. This project started in 2009 and involves 12
co-investigators, as well as participation by other industry
professionals.
Gerrit received his B.S. and M.S. degrees in Chemistry
from the University of Utrecht, Utrecht, The Netherlands,
in 1970 and 1972, respectively, and a Ph.D. degree in
Physical Biochemistry from the University of Calgary,
Calgary, Alberta, Canada, in 1975.
Dr. Peter F. Sanders is a Research
Science Consultant in Saudi Aramco’s
Research & Development Center
(R&DC). He worked for 12 years as a
Senior Microbiologist and Research
Manager for Oil Plus Ltd., an oil field
consultancy company in the U.K.,
working on solving microbiological problems for most of
the major oil field operators all over the world. Prior to
that, Peter was a Research Fellow at Aberdeen University,
Scotland, and ran a small oil field microbiology company
He joined Saudi Aramco in 2001, and has been working
on new technologies to predict, monitor, assess and control
microbial corrosion, biofouling and contamination
problems in water injection, oil production, and
transportation and utilities systems. Peter has also been
studying downhole microbial growth and microbiology in
extreme environments to develop biotechnology-based
processes. He has also consulted widely within Saudi
Aramco to address operational problems caused by
microbial growth in oil field systems.
He received his B.S., M.S. and Ph.D. degrees in
Microbiology from Exeter University, Exeter, U.K.
Dr. Tony Y. Rizk joined Saudi
Aramco’s Research & Development
Center (R&DC) in July 2006 and is
currently a Science Specialist.
Throughout his career in the oil and
gas industry for well over two decades,
Tony has initiated and managed a
number of research and deployment projects. He also
pioneered the development of new technologies that have
been successfully implemented in the oil and gas industry.
Tony assumed a number of roles while at the R&DC,
and he has been handling the Biotechnology Technical
Services activities for the last two years. His work has
involved microbially induced corrosion, encapsulation for
downhole slow release, MEOR methodologies, reservoir
souring and control mechanisms, nitrate corrosion,
corrosion inhibitor selection, and corrosion evaluation
under high shear stress and hydrotesting.
Tony has chaired a number of international and regional
conferences, including the Energy Institute Reservoir
Microbiology Forum, London, U.K. (2007-2008), the Saudi
Aramco Technical Exchange Forum (2009), Technical
Chairman of the Middle East Corrosion Conference
(2011), Session Chairman of the Society of Petroleum
Engineers (SPE) conference on MIC at Calgary, Canada
(2009), and Session Chairman of both Chemindex and
Labtech in Bahrain (2010) and Qatar (2011), respectively.
He is also currently the Technical Chairman of the 15th
Middle East Corrosion Conference and Exhibition to be
held in Bahrain in 2014.
Tony received his B.S. in Industrial Engineering and
graduated with a Ph.D. in Corrosion Science from
Manchester University, Manchester, U.K., in 1992.
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Comprehensive Diagnostic and Water
Shut-off in Open and Cased Hole
Carbonate Horizontal Wells
Authors: Nawawi A. Ahmad, Hussein S. Al-Shabebi, Dr. Murat Zeybek and Shauket Malik
ABSTRACT
Increases in water production can significantly reduce well
performance and the life of a well, leading to decreased oil
production. To mitigate this situation, water management is
crucial. Water influx can occur through several mechanisms
and approach from several directions. Accurate diagnostic information is important for the design of successful shut-offs
and effective results. One option is to isolate the water producing zone with a rigless water shut-off (WSO) technique, which
is less costly than the use of workover rigs for interventions.
This article presents case histories of five horizontal wells
drilled in carbonate formations and producing excess water;
three were completed in open hole and two were cased. A multiphase production logging (MPL) tool, equipped with five
miniaturized spinners for phase velocity measurement, and six
electrical and six optical probes for holdup data, provided important diagnostic data for the decision making on remedial
actions. Using the tool data, the operator pinpointed the water
entries and performed shut-off operations based on the source
of the entries and water flow profiles. Subsequent production
test results showed that the water cut was reduced in all the
wells. Examples from open and cased hole completions are
shown, utilizing a number of different shut-off techniques. In
addition, oil production was considerably increased in many of
the wells. These results demonstrate that accurate diagnostic
information and an integrated approach are keys to successful
rigless WSOs.
INTRODUCTION
Most horizontal wells are drilled to improve oil production
and to minimize water production. In addition, the drilling of
horizontal sidetracks is increasing to further maximize oil recovery. The monitoring and management of these wells are
challenging operations because their completions and interventions are complex, and it is difficult to obtain accurate diagnostics in the complex flow regimes occurring in their
undulating deviations. It has been shown1, 2 that the use of an
integrated compact production logging tool with multiple
mini-spinners can provide accurate information on water
entries and flow profiles.
52
For many reasons, water production can increase earlier
than expected and impair the performance of the well. In
some cases, horizontal wells have died suddenly3. Water shutoff (WSO) and remedial work is crucial to revive them and
to reduce water cut to improve well performance. Successful
shut-offs require an understanding of the water entry mechanism, the reservoir heterogeneities and the wellbore operations.
Accurate diagnostics and successful remedial actions can
lead to significant improvements in well performance. In one
case, this process led to the significant reduction of gas entry4.
Because all wellbore and reservoir parameters and heterogeneities are unique, each case requires a customized workflow.
The feasibility of an intervention depends on the specific
conditions and the environment in each case. For illustration
purposes, this article presents several field examples, including
open hole and cased hole completions, with well history
and performance documented before and after the remedial
work.
INTEGRATED PRODUCTION LOGGING TOOL
As described in several publications, the production logging
tool, used in these case studies provides continuous multiphase
velocity distribution measurements and holdup data that are
then used to identify water entries, establish water profiles and
analyze complex horizontal flow behavior.
The vertical-axis orientation of the sensors enables the
measurement of mixed and segregated flow regimes, including
direct independent measurement of gas velocity in a multiphase horizontal well. All measurements are taken simultaneously at the same depth level.
The tool runs are decentralized in highly deviated and horizontal wells to ensure proper sensor placement across the vertical axis. Caliper and tool orientation measurements enable
real-time calculation of the sensors’ positions.
Each spinner responds to the velocity of the fluid passing
through it, which enables the calculation of the multiphase velocity profile. Each of the six electrical probes and six optical
probes reads the localized water and gas holdup, which enables the calculation of the multiphase holdup profile. The corresponding holdup and velocity profiles permit the calculation
of the multiphase flow rate profile using dedicated algorithms.
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WATER MANAGEMENT WITH SHUT-OFFS
The production of oil reservoirs is affected by water production, which can originate from either aquifers or water injection. In fact, water production is a direct consequence of
hydrocarbon depletion in all fields5. The production of water,
its handling at the surface and the re-injection process comprise the “water cycle,” which must be effectively managed.
Water control services are one of the fastest and least costly
routes to reduce operating costs and simultaneously improve
hydrocarbon production. High water production can have adverse effects on reservoir performance, which can result in production losses; it can add to oil production cost with increased
lifting, separation and disposal costs, and it can lead to scaling,
corrosion and degradation in the wellbore, tubing, flow lines
and processing facilities. Water management is crucial to reduce water production, optimize oil production and either increase well life or revive dead wells. The detection of water
entry intervals and the establishment of production profiles are
needed to gain the understanding of reservoir dynamics and
well performance that are necessary to achieve successful
water isolation.
Whether options for effective WSO are feasible depends
on several reservoir and well parameters and diagnostic
results. The solutions can include recompletion, mechanical
isolation, chemical isolation and sidetracks. The option discussed in this article involves isolating the water producing
zone through a mechanical means that (except in one instance)
does not require a workover rig, which is easier and cheaper to
implement.
multiphase flow profile and the water entry intervals. To date,
no MPL runs have been made on these wells since the WSO
job. Performance of the wells is also provided before and after
the WSO job (blue curve as water cut, green curve as oil production). For the operations presented in this article, pre-job
preparation, including assembly of drilling history, production
history, open hole logs and well details, was carried out to ensure effective data acquisition. During the job, data was transmitted and observations were communicated to the well site
for real-time decisions to ensure the objectives of reduced
water production were accomplished.
Well-A: Shut-off Job Using Inflatable Packer (Rigless
Operation)
Background: Well-A, as illustrated in Figs. 2 and 3, was drilled
underneath a gas cap and completed as a horizontal cased hole
oil producer in zones 2 and 3. Due to lost circulation encountered at X265, the well was completed with a 4½” perforated
liner to avoid gas cusping. These lost circulation zones have
tight intervals above and below, as illustrated by the blue
arrows in track 9 of Fig. 2. The well has seven perforations
selectively placed in zones 2 and 3.
Logging Job: The MPL tool was deployed using 2” coiled tubing (CT), with about 87% coverage of the completed interval;
greater coverage was not attempted because of indications that
deeper logging may cause the tool to get stuck. Subsequently,
the relevant intervals were covered so that an appropriate
WSO decision could be made. The logging was done under
shut-in and natural flowing conditions.
FIELD EXAMPLES
Logging Results: Figure 2 shows the results, with the well
All the wells presented in this article were drilled in the Jurassic formation of a giant oil field. The formation is thick and
has high permeability. The formation is divided from top to
bottom into lithostratigraphic zones 1 to 4; zones 2 and 3 are
divided into subzones A and B. The best reservoir quality is in
zone 2, described as having been formed in a high energy, shallow marine environment. The oil is of relatively light quality,
and the formation water has a very high salinity, above 200K
ppm total dissolved solids. The field has been under peripheral
water injection for a long time to maintain pressure and improve production. The multiphase production logging (MPL)
tool, Fig. 1, was run in all these examples to determine the
Fig. 1. MPL tool.
Fig. 2. Results from integration of production log and open hole formation
evaluation data in Well-A.
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sketch/perforated interval, flow profile and open hole data displayed in tracks 2, 6 and 9, respectively. The MPL data analysis showed that all of the water production was identified as
coming from the second perforation (perfo-2) and the fourth
perforation (perfo-4), and most of the produced oil was identified as coming from the first perforation (perfo-1), as shown in
track 6, Fig. 2. Perforations 2 and 4 were in communication
(indicated by downward water cross flow) during shut-in, as
shown in track 8, Fig. 2. It was also observed that perforations
3, 5, 6 and 7 were not contributing to oil production.
Shut-off Job: The MPL data showed that all of the water production was identified from below X600, and the open hole
log data showed that there are tight intervals above X600.
Therefore, a WSO job was performed by setting an inflatable
packer at X560 using CT, as illustrated in track 10, Fig. 2.
Consequently, the producing perforated interval after the WSO
job is now distinctly above the tight zones at X560.
evaluation data in Well-B.
Shut-off Result: The production history is shown in Fig. 3,
with the WSO event indicated by an orange dashed line. After
the WSO job, compared with values recorded during the MPL
run, the water production dropped sharply — by about 45%
— and oil production nearly doubled. This is considered to be
a successful WSO job and was done at relatively low cost.
Well-B: Shut-off Job through a Five-stage Cementing Job
(Rigless Operation)
Background: Well-B, as illustrated in Figs. 4 and 5, was drilled
and completed as a horizontal open hole oil producer over
zones 2 and 3. Open hole logs showed several tight/low porosity intervals; the relevant one for this example is at X160
(shown by a blue arrow in track 7, Fig. 4).
Logging Job: The MPL job was done using 2” CT, with about
99% coverage of the completed interval. The logging was done
under shut-in and natural flowing conditions.
sketch, flow profile and open hole data displayed in tracks 2, 6
and 7, respectively. The MPL data analysis showed that the
Fig. 3. Production history before and after WSO in Well-A.
54
Fig. 5. Production history before and after WSO in Well-B.
flow zones can be divided into three major units: X030 to
X160, X160 to X400, and below X400. All of the water production was identified as coming from below X160, and most
of the produced oil (about 78%) was identified as coming
from X030-X160 (track 6, Fig. 4).
Shut-off Job: A WSO job was accomplished through a fivestage cementing job, performed over the horizontal section
from X150 to X570 (track 8, Fig. 4). Consequently, the producing open hole interval after the WSO job is now above the
tight zone at X160.
Shut-off Result: The production history is shown in Fig. 5 with
the WSO event indicated by an orange dashed line. After the
WSO job, compared with values recorded during the MPL
run, the water production dropped sharply by about 48%, and
oil production has remained constant over a 4-month period.
This is also considered a successful WSO job, as oil production
remained constant despite reducing the open hole length/completed interval by about 75%.
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Well-C: Shut-off Job Using Mechanical Plug and Cement
(Rigless Operation)
Background: Well-C, as illustrated in Figs. 6 and 7, was drilled
and completed as a horizontal cased hole oil producer in zone
2A. Open hole logs showed several tight/low porosity intervals; the relevant one here is at X810 (shown by a blue arrow
in track 7, Fig. 6). The well was completed with a 4½” equalizer string and inflow control devices (ICDs), with seven equalizer segments separated using six mechanical open hole
packers. During the MPL job, the well was dead.
Logging Job: The MPL tool was deployed using 2” CT and a
friction reducer to extend the reached depth and avoid the tool’s
damage, with 98% coverage of the completed interval. The logging was only done under shut-in conditions because the well was
dead and no attempt to date had been made to revive the well.
sketch/equalizer intervals (marked with numbers for easy
reference), shut-in profile and open hole data displayed in
tracks 2, 6 and 7, respectively. The MPL tool data analysis
showed that a strong upward cross flow of water was identified as coming from the seventh equalizer segment (blank pipe
with bull plug), and it was concluded that the bull plug was
broken. This upward water cross flow was the reason preventing the well from naturally flowing.
Shut-off Job: The MPL data showed that all of the water
movement (cross flow) during shut-in was coming from the
seventh equalizer segment (below X880). Because of the tight
interval at X810, the shut-off job was done by setting a mechanical plug at X560 (as illustrated in yellow in track 8, Fig.
6) and pumping cement through it. Consequently, the producing equalizer interval after the WSO job is now above the tight
zone at X810.
Shut-off Result: The production history is shown in Fig. 7,
with the WSO event indicated by an orange dashed line. After
the WSO job, the well was revived and flowed naturally with
15% water cut, producing thousands of barrels of oil per day.
This is a remarkably successful WSO job; a dead well was revived to produce oil at a high rate and relatively low water cut.
Well-D: Shut-off Job Using Blank Pipe and Equalizer String
(Workover Rig Operation)
Background: Well-D, as illustrated in Figs. 8 and 9, was drilled
and completed as a horizontal open hole oil producer over
zone 2A. Open hole logs showed several tight/low porosity intervals; the relevant one here is at X250, shown by a blue arrow in track 11, Fig. 8. The well was logged three times using
MPL tools over a four-year period, from 2005 to 2008.
Logging Job: The logging summary of each job is as follows:
evaluation data in Well-C.
Fig. 7. Production history before and after WSO in Well-C.
evaluation data in Well-D.
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Fig. 9. Production history before and after WSO in Well-D.
• First run in 2005: The job was done with a 2” CT, with
61% coverage over the objective interval, in both shutin and flowing conditions.
• Second run in 2007: The job was done with 2⅜” CT,
with 89% coverage over the objective interval, only in
shut-in condition because of operational issues.
• Third run in 2008: The job was done with 2⅜” CT,
with 99% coverage over the objective interval, to avoid
the tool’s damage. The relevant intervals were covered,
enabling appropriate production and reservoir management decisions. The well was logged under shut-in
and natural flowing conditions.
Logging Results: Figure 8 shows the results of all three MPL
jobs, with the well sketch, flow profile from 2005, shut-in
profile from 2007, flow profile from 2008, shut-in profile from
2008 and open hole data displayed in tracks 2, 5, 7, 9, 10 and
11, respectively.
The logging result summary of each job is as follows:
• First run in 2005: The MPL showed no water, which
were also in agreement with the test results. The MPL
data showed major oil entry (82% of total oil) at
intervals between X250 and X330 (track 5, Fig. 8). This
was attributed to the presence of conductive fractures
over this interval. No cross flow was observed during
the shut-in and flowing surveys.
• Second run in 2007: The MPL showed a strong
downward oil cross flow during the shut-in survey (no
flowing survey was done). It was discovered that the zones
with conductive fractures (between X250 and X330)
were responsible for this cross flow (track 7, Fig. 8).
• Third run in 2008: The MPL showed a strong
downward oil and water cross flow during both shut-in
and flowing surveys. During the flowing survey, the
shallower fracture at X260 was bringing all the water to
the wellbore, as shown in track 9, Fig. 8. During the
shut-in survey, it was also discovered that the zones
with conductive fractures (between X250 and X330)
were responsible for this cross flow (track 10, Fig. 8).
Shut-off Job: From the latest 2008 MPL data, the water
56
evaluation data in Well-E.
Fig. 11. Production history before and after WSO in Well-E.
production was identified as coming from the shallow fracture
at X260. The WSO job was done by installing an equalizer
string with bull plug (as illustrated in track 12, Fig. 8). Blank
pipe was installed against the conductive fractures (between
X250 and X330) to eliminate the cross flow and the major water production from this highly conductive interval.
Shut-off Result: The production history, Fig. 9, with the WSO
event is indicated by an orange dashed line. After the WSO
job, the water production dropped sharply to almost a dry oil
well, and oil production increased about three times. This is
considered to be a successful WSO job, even though it was
done at a high cost.
Well-E: Shut-off Job Using Inflatable Cement Retainer and
Cement Plug (Rigless Operation)
Background: Well-E, as illustrated in Figs. 10 and 11, was
drilled and completed as a horizontal open hole oil producer
over zones 2, 3 and 4. Open hole logs showed several tight/low
porosity intervals; the relevant one here is at X240, indicated
by a blue arrow on track 7, Fig. 10.
Logging Job: The MPL job was done using a 1¾” CT, with
62884araD8R1_ASC026 3/15/13 11:38 PM Page 6
80% coverage over the objective interval. The limited coverage
was because of CT lockup; however, the relevant intervals
were covered, enabling appropriate production and reservoir
management decisions. The logging was done under shut-in
and natural flowing conditions.
sketch, flowing profile and open hole data displayed in tracks
2, 6 and 7, respectively. The MPL tool data indicated that all
of the water production was emanating from the fractured
zone intersecting the wellbore at X425, which also contributed
about 42% of the total oil. It was observed two years after obtaining the MPL data, that the well was dead, possibly due to
excessive water production from the fractured zone at X425.
Shut-off Job: The WSO job was done by installing two inflatable cement retainers, squeezed with cement, at X236 and
X200; the top of the cement was at X183 (illustrated in track
8, Fig. 10). Consequently, the producing open hole interval
after the WSO job is now above the tight zone at X240.
Shut-off Result: The production history, Fig. 11, with the WSO
event indicated by an orange dashed line. After the WSO job,
the water production dropped sharply by about 80%, and oil
production increased by about one-third. This is considered to
be a successful WSO job.
CONCLUSIONS
Integration of MPL results, open hole data and other static and
dynamic data is essential for a successful shut-off job (and other
production and reservoir management decisions). The presented
results demonstrate that successful WSO is achievable in horizontals wells, even though there is a potential for water coning
due to the homogeneous character and high permeability of
the reservoirs. It was also observed that reservoir barriers/low
permeability intervals above the shut-off interval play an important role in preventing water coning after the WSO job.
These field examples showed that increased water production can significantly reduce oil production and impair well
performance. In one example, water production had caused
the horizontal well to become a dead well. As demonstrated in
that example, the execution of a successful WSO job can revive
such a well and make it flow naturally at a high rate and at
low water cut.
Accurate production logging diagnostic input and a methodical shut-off design can lead to significant improvement in
well performance and increased well life. Although the rigless
shut-off technique is generally desired because it is a fast and
cost-effective intervention, the shut-off solution may require
more expensive options, such as using a workover rig to install
equalizer strings and ICDs and/or to sidetrack the well. The
success of WSO depends on accurate problem diagnostics,
careful job design and excellence in execution.
RECOMMENDATIONS
The following guidelines and recommendations will improve
the potential for WSO success:
1. Production logging data should be recent when planning the
shut-off design and execution, as the reservoir dynamics can
rapidly change, especially in mature fields.
2. Ensure there is a prominent reservoir barrier/low permeability zone above the shut-off interval, as shown by open hole
log and/or image data.
3. Numerical simulation within an integrated petroleum engineering study will help assess more quantitatively the effectiveness of the shut-off job and the added value (cost, rate,
etc.).
ACKNOWLEDGMENTS
and Schlumberger for their permission to present and publish
this article and to thank Mohammad M. Al-Mulhim for providing relevant data.
U.A.E., November 11-14, 2012.
REFERENCES
1. Baldauff, J., Runge, T., Cadenhead, J., Faur, M.,
Marcus, R., Mas, C., et al.: “Profiling and Quantifying
Complex Multiphase Flow,” Oilfield Review, Vol. 16,
No. 3, October 1, 2004, pp. 4-13.
2. Al-Muthana, A.S., Ma, S.M., Zeybek, M. and Malik, S.:
“Comprehensive Reservoir Characterization with
Multiphase Production Logging,” SPE paper 120813,
presented at the SPE Saudi Arabia Section Technical
Symposium, al-Khobar, Saudi Arabia, May 10-12, 2008.
3. Nawawi, A., Bawazir, M., Zeybek, M. and Malik, S.:
“Pinpointing Water Entries in Dead Horizontal Wells,”
IPTC paper 15375, presented at the International
Petroleum Technology Conference, Bangkok, Thailand,
February 7-9, 2012.
4. Al-Behair, A., Malik, S., Zeybek, M., Al-Hajari, A. and
Lyngra, S.: “Real Time Diagnostics of Gas Entries and
Remedial Shut-off in Barefoot Horizontal Wells,” IPTC
paper 11745, presented at the International Petroleum
Technology Conference, Dubai, U.A.E., December 4-6,
2007.
5. Bailey, B., Crabtree, M., Tyrie, J., Kuchuk, F., Romano, C.,
Roodhart, L.; “Water Control,” Oilfield Review, Vol. 12,
No. 1, 2000, pp. 30-51.
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BIOGRAPHIES
Nawawi A. Ahmad is a Petroleum
Engineer Specialist and is currently the
Lead Engineer for day-to-day
evaluation of production logs for all
fields in Saudi Aramco. He started his
oil field career in 1989 with Shell in
Southeast Asia as a Well Site
Petroleum Engineer, Operational Petrophysicist and Field
Study Petrophysicist in new and mature oil and gas fields.
Nawawi then worked as a Senior Petrophysicist and field
study leader for Petroleum development Oman in the
Middle East. His last position before joining Saudi Aramco
was as a division head of one of the petrophysic units in a
Shell operating company in Southeast Asia.
Nawawi received his B.Eng. degree in Mining and
Petroleum Engineering from Strathclyde University,
Glasgow, U.K., in 1989 and an M.B.A. from Brunei
University, Brunei, in 2005.
He has been a member of the Society of Petroleum
Engineers (SPE) since 1989.
Hussain S. Al-Shabibi joined
Schlumberger Oilfield Services in 2006
as a Borehole Production Engineer in
the Petro-Technical Services (PTS)
segment. He has 6 years of experience
in job planning, real-time monitoring
and post-acquisition data processing
and interpretation related to production logging in vertical
and horizontal wells. Hussain also assists the company in
the marketing and support of integrated solutions.
Hussain has been a member of the Society of Petroleum
Engineers (SPE) since 2003.
58
Dr. Murat Zeybek is a Schlumberger
Reservoir Engineering Advisor and
Reservoir and Production Domain
Champion for the Middle East area.
He works on analysis/interpretation of
wireline formation testers, pressure
transient analysis, numerical modeling
of fluid flow, water control, production logging and
reservoir monitoring.
He is a technical review committee member for the
Society of Petroleum Engineers (SPE) journal Reservoir
Evaluation and Engineering. Murat also served as a
committee member for the SPE Annual Technical
Conference and Exhibition, 1999-2001. He has been a
discussion leader and a committee member in a number of
SPE Applied Technology Workshops (ATWs), including a
technical committee member for the SPE Saudi Technical
Symposium, and he is a global mentor in Schlumberger.
Murat received his B.S. degree from the Technical
University of Istanbul, Istanbul, Turkey, and his M.S.
degree in 1985 and Ph.D. degree in 1991, both from the
University of Southern California, Los Angeles, CA, all in
Petroleum Engineering.
Shauket Malik is currently working as
a Senior Geoscientist in Saudi Arabia
with Schlumberger where he has been
for over 20 years. He started his career
in Iraq as a Log Analyst (open hole)
and then worked in Angola as a Log
Analyst (open and cased hole). Shauket
was transferred to Saudi Arabia, where he led the Data
Management group and then worked as a Log Analyst
(open and cased hole) until 1999. In 2000, he was
transferred to Reservoir Domain and then to Production
Domain, where currently he is performing vertical and
horizontal production analysis.
Sauket received his B.S. degree in Physics and a M.S.
degree in Applied Mathematics (fluid mechanics and
dynamics), both from Punjab University, Chandigarh,
India.
Shauket is the author and coauthor of numerous papers
on production domain.
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Black Oil, Heavy Oil and Tar in One Oil
Column Understood by Simple Asphaltene
Nanoscience
Authors: Douglas J. Seifert, Dr. Murat Zeybek, Dr. Chengli Dong, Dr. Julian Y. Zuo and
Dr. Oliver C. Mullins
ABSTRACT
A Jurassic oil field in Saudi Arabia is characterized by black oil
in the crest with mobile heavy oil underneath, all of it underlain by a tar mat at the oil-water contact (OWC). The viscosities in the black oil section of the column are fairly similar and
are quite manageable from a production standpoint. In contrast, the mobile heavy oil section of the column contains a
large continuous increase in asphaltene content with increasing
depth, extending to the tar mat. The tar shows very high asphaltene content, but it is no longer monotonically increasing
with depth. Because viscosity depends exponentially on asphaltene content in these oils, the observed viscosity varies from
several to ~1,000 centipoise (cP) in the mobile heavy oil and
increases to far greater viscosities in the tar mat. Both the excessive viscosity of the heavy oil and the existence of the tar
mat present major, distinct challenges in oil production. Conventional pressure-volume-temperature modeling of this oil
column grossly fails to account for these observations. Indeed,
the very large height of this oil column poses a stringent challenge for any corresponding fluid model. A simple new formalism used to characterize the asphaltene nanoscience in crude
oils, the Yen-Mullins model, has enabled development of the
industry’s first predictive equation of state (EoS) for asphaltene
gradients: the Flory-Huggins-Zuo (FHZ) EoS. For a low gasoil ratio (GOR) such as those in this field, the FHZ EoS reduces to the simple gravity term. Robust application of the
FHZ EoS, employing the Yen-Mullins model, accounts for the
major property variations in the oil column and by extension,
the tar mat as well. Moreover, as these crude oils are largely
equilibrated throughout the field, reservoir connectivity is indicated in this field. This novel asphaltene science is dramatically
improving the understanding of important constraints on oil
production.
INTRODUCTION
Huge viscosity gradients in oil columns have an enormous
impact on production. Oil flow rate depends inversely on
viscosity. Water sweep efficiency is greatly reduced when the
viscosity ratio between oil and water exceeds ~5 centipoise
(cP), causing water fingering instead of sweep. Tar mats at the
oil-water contact (OWC) can preclude any aquifer support and
any effectiveness of water injection in the aquifer. In spite of
the overriding impact of viscosity gradients in black oil, heavy
oil and tar, there has been very little understanding of the origin and distribution of these gradients. The reason for this
glaring deficiency in petroleum science and engineering is simple to understand. The viscosity gradients in black oil/heavy oil
systems are dominated by asphaltene gradients, and until recently, there has been no proper theoretical framework for
understanding the distribution of asphaltene gradients in oil
reservoirs. For example, the ubiquitous use of the cubic equation of state (EoS) in reservoir models traces back to the Van
der Waals Equation, which was developed to treat gas-liquid
equilibria and has no provisions for handling colloidal solids,
such as the asphaltenes. The reason for the inability to treat asphaltenes in thermodynamic models, so as to give asphaltene
gradients, is quite clear; there has been a long-standing, ordersof-magnitude debate in the asphaltene science literature about
the size of asphaltene molecules1. If the size is unknown, then
the effects of gravity are indeterminate, thereby precluding the
modeling or prediction of gradients. In short, this deficiency
has now been resolved: the molecular and colloidal sizes of
asphaltenes in crude oil and in laboratory solvents have been
codified in the Yen-Mullins model2. Indeed, with this resolution, the Flory-Huggins-Zuo Equation of State (FHZ EoS) has
been developed3 and proven to give accurate asphaltene gradients in heavy oils4, black oils5 and condensates6.
In this article, a brief review of the new asphaltene formalism is given, showing that the formalism is extremely simple
for low gas-oil ratio (GOR) fluids. This simple formalism is
then applied to a double plunging anticlinal oil field (4-way
closure) that has black oil in the crest, mobile heavy oil in the
flank and a tar mat at the OWC. (For this work, mobile heavy
oil is defined to have a viscosity less than ~1,000 cP; in many
fields such oil is produced conventionally.) It is shown that the
simple precepts herein properly account for detailed observations; chemical analysis of the oils and tar show that the simple
model captures the primary features of the data. Indeed, the
treatment of such important properties, such as the viscosity of
a large volume of oil over great distances, with a simple, effective model might be called stunning. Certain unresolved issues
are discussed within the context of this new foundation of
asphaltene science.
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ASPHALTENE NANOSCIENCE
The FHZ EoS
The Yen-Mullins Model
With the size known for these distinct asphaltene species, a
first principles model can be developed for describing asphaltene gradients. The Flory-Huggins equation has been used extensively to describe asphaltene solubility and asphaltene phase
behavior9. Adding the gravity term to the Flory-Huggins equation enables the calculation of asphaltene gradients in reservoirs. This modification yields the powerful FHZ EoS10:
After a lengthy literature debate, the centroid and distribution
of asphaltene molecular weights and sizes has largely been resolved by many different experimental methods and by many
different groups around the world7. In addition, there is now
extensive consensus on the nanocolloidal picture of asphaltenes.
Most importantly, the fact that there are now two nanocolloidal species of asphaltenes has a major bearing on asphaltene
and viscosity gradients in oil reservoirs. The dominant molecular and colloidal structures are represented in a model with
prototypical structures, now called the Yen-Mullins model8. A
schematic of the model showing the nominal sizes of molecules, nanoaggregates and clusters is shown in Fig. 1.
Generally, different fields are seen to exhibit these sizes
within 10% variability. It is not currently known whether
there are actual size differences in the asphaltene nanoaggregates, varying from one oil to the next, or whether apparent
differences are actually from errors in measurements. It is important to note, however, that asphaltene molecular properties
from many different crude oils are seen to be rather uniform
and not dependent on the specific crude oil7.
The salient components of this nanoscience model are as
follows: asphaltene molecular weights are ~750 g/mole with a
range of 500 g/mole to 1,000 g/mole. The predominant molecular architecture has a large central ring system with peripheral groups (Fig. 1, Left). At low asphaltene concentrations,
asphaltene molecules are not aggregated, and asphaltenes are
dispersed as molecules; this applies to condensates6. At higher
concentrations, such as in black oils, asphaltene molecules selfassemble into nanoaggregates (of roughly six molecules) with a
single, central, disordered stack of aromatic groups (Fig. 1,
Center). At yet higher asphaltene concentrations, for example,
found in mobile heavy oil, asphaltene nanoaggregates self-assemble into clusters of roughly eight nanoaggregates (Fig. 1,
Right). These structures figure prominently when determining
the direct effect of gravity on asphaltene gradients.
Fig. 1. The Yen-Mullins model of asphaltene science showing the predominant
molecular and colloidal structures of asphaltenes1. Left: At low asphaltene concentrations such as in condensates, asphaltenes are dispersed as molecules. Center: At
larger asphaltene concentrations such as in black oils, asphaltene molecules selfassemble, forming nanoaggregates with about six molecules per nanoaggregate.
Right: At even higher asphaltene concentrations such as in (mobile) heavy oils,
asphaltene nanoaggregates self-assemble, forming asphaltene clusters with about
eight nanoaggregates.
60
(1)
where OD(hi) is the optical density or oil color (typically
measured by downhole fluid analysis) at height hi in the oil
column, f a(hi) is the asphaltene concentration at height hi, va
is the molar volume of the asphaltene species of interest (either
molecule, nanoaggregate or cluster, cf. Fig. 1), v is the molar
volume of the crude oil, g is the earth’s gravitational acceleration, Δρ is the density contrast between the asphaltene and the
liquid crude oil, δa is the solubility parameter of the asphaltene, δ is the solubility parameter of the crude oil, k is Boltzmann’s constant, and T is temperature. The color of the crude
oil scales linearly with asphaltene content, as has been shown
in numerous case studies.
The first term in the argument of the exponential is the
gravity term. For low GOR black oils and heavy oils, the gravity term dominates. This gravity term contains Archimedes’
buoyancy, which has had two millennia of validation, va Δρg.
The asphaltenes are negatively buoyant (more dense) than the
liquid crude oil. Newton’s force (F=ma) is mass times acceleration. With Archimedes’ buoyancy, it is not the total mass of the
asphaltene species that matters but rather the effective buoyant
mass, va Δρ (volume times density = mass). This buoyant mass
is multiplied by g to obtain the gravitational force on the asphaltene particle. Of course, with larger asphaltene species
(with larger volume va), the force is greater. In effect, the energy required to lift an asphaltene particle off the base of the
oil column to some height, h, equals the gravitational force,
va Δρg, multiplied by h.
If gravity were the only determinant for the asphaltene distribution, then all asphaltenes would be at the base of the oil
column; however, as Boltzmann showed over 100 years ago,
available thermal energy can lift particles to higher energy
states. In a gravitational field, this amounts to thermal energy
lifting particles off the floor to some higher height. The Boltzmann distribution describes the population distribution of
ground (E=0) and excited (ΔE) states in the very simple form:
exp{-ΔE/kT}. This applies to all systems. Most importantly, the
Boltzmann distribution represents an equilibrated state.
Having particles in an excited state is not a transient condition;
it is an equilibrium condition that will not change with time.
One system that clearly shows the Boltzmann distribution is
the earth’s atmosphere. If gravity were the only determinant
for the distribution of air molecules, then all air molecules
62884araD9R1_ASC026 3/15/13 11:41 PM Page 3
Fig. 2. Calculated atmospheric pressure from the equation exp{-mgh/kT} using the
weighted average of the molecular mass of air molecules (and 298° Kelvin) closely
matches observations. The prediction for Mount Everest is slightly high because of
the assumption of constant room temperature. Virtually the same equation applies
to mobile heavy oil gradients, substituting the negative buoyancy of asphaltene
particles for mass2.
would be pulled to the surface of the earth and everyone
would suffocate. Thermal energy lifts air molecules to elevations above the earth’s surface. Because air molecules are small
(two heavy atoms in N2 and O2), the available thermal energy
lifts the air molecules to a great height. Here, the air molecules
are suspended in a vacuum, so the Boltzmann distribution is
simply exp{-mgh/kT}, where m is the weighted molar mass of
the air molecules, 80% N2 and 20% O2. This is what is plotted in Fig. 2 with T=298° Kelvin. Such a simple prediction,
Fig. 2, closely matches observations.
For asphaltenes, one replaces m with va Δρ, thereby using
Archimedes’ buoyancy (essentially because the liquid is incompressible, so buoyancy is used), and the rest of the Boltzmann
distribution expression remains the same as for the atmosphere.
For low GOR crude oils, the asphaltene gradient is predominantly just given by the gravity term with all variables defined
above.
(2)
Asphaltene molecules contain ~70 heavy atoms, nanoaggregates contain ~400 heavy atoms, and clusters contain 3,000
carbon atoms. Consequently, the gravitation gradient of
asphaltenes depends critically on the particular asphaltene
species. For a fixed thermal energy (temperature), asphaltene
molecules are suspended to a considerable height (but much
less than air molecules, which have only two heavy atoms),
nanoaggregates are suspended less high, and clusters with their
~3,000 heavy atoms reach the least height. Figure 3 shows the
gradients for asphaltenes, presuming molecules, nanoaggregates
and clusters in a crude oil of 0.90 g/cc liquid phase density and
T=393° Kelvin.
In Eq. 1, the second and third terms in the argument of the
exponential incorporate the effects of entropy. This term tends
to be small, so it can largely be ignored. The effect of entropy
Fig. 3. The asphaltene gradient from the gravity term alone for the three
asphaltene species in the Yen-Mullins model from Fig. 1. The large clusters (5.0
nm) show a rapid decline of % asphaltene with height, while the intermediate
nanoaggregates (2.0 nm) and the small molecules (1.5 nm) show a very gradual
decline. For low GOR crude oils, the gravity term tends to dominate the
asphaltene gradient, while for large GOR crude oils, the solubility term in the
FHZ EoS can dominate the asphaltene gradient (cf. Eq. 1).
is to randomize or equally disperse the asphaltenes.
The last term in the argument of the exponential of Eq. 1 is
the solubility term. In chemistry “like dissolves like,” and this
chemical heuristic is formalized in the solubility term. For example, water and alcohol are mutually soluble since both have
OH groups. In contrast, oil with its CH groups is dissimilar to
water with its OH groups, so oil and water are not mutually
soluble. Here, given an interest in gradients, it is the variation
of the solubility term with height in the oil column that is important in establishing asphaltene gradients. The asphaltene
solubility parameter is determined by asphaltene chemical
properties and is invariant, aside from a slight temperature
dependence10. If the composition of the liquid oil does not
change in an oil column, then there is no variation of the solubility parameter or solubility term in Eq. 1 vs. height in the oil
column, so the gravity term still dominates.
The primary factor that determines whether or not there is a
variation of the liquid oil solubility parameter (for equilibrated
oil columns) is the solution gas content. Solution gas is a colorless gas, where asphaltenes are a dark brown solid — they are
chemically very different and don’t dissolve in each other.
Asphaltene does not partition to gas, making gas colorless.
Asphaltene does not dissolve well in crude oil with high solution gas. If there is a significant solution gas variation in an
oil column, then there will be a large variation of the liquid oil
solubility parameter with height, and this can dominate creation of an asphaltene gradient. Crude oils with low solution
gas have largely homogeneous solution gas. For these crude
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oils, the gravity term dominates. For crude oils with high solution gas (>700 scf/bbl), there is a significant solution gas variation, and the solubility parameter then becomes dominant,
creating the asphaltene gradient. The GOR variation is largely
traceable to compressibility. Crude oils with high solution gas
are compressible. As the hydrostatic head pressure of the oil
column increases density at the base of the column, the light
components get “squeezed out” of the base, creating a solution
gas variation. Crude oils with low solution gas are incompressible. For these oils, the hydrostatic head pressure does not increase the oil density at the base of the column; therefore, there
is no density gradient to drive a compositional gradient.
BLACK OIL, HEAVY OIL AND TAR IN A SINGLE
RESERVOIR
Mobile Heavy Oil
A large anticlinal structure contains a black oil reservoir of low
GOR11. The asphaltenes underwent some instability, forming
the mobile heavy oil section of the oil column and a tar mat at
the OWC. Here, the focus is on the mobile heavy oil and the
tar mat in the field. Small fractions of the asphaltenes in the
black oil were destabilized, possibly by a gas or condensate
charge. The destabilized asphaltenes formed clusters, which
then accumulated at the base of the oil column. In a local section of the field spanning roughly 8 kilometers, the asphaltenes
are in clusters and are equilibrated, Fig. 4, in total agreement
with the reservoir scenario just discussed11.
Figure 4 also shows that the simple gravity term of the FHZ
EoS accounts for the huge increase in asphaltene content at a
height of 120 ft. Such a large height in the oil column and the
corresponding sixfold increase in the asphaltene content from
top to bottom represent a stringent test of any model. The
gravity term has only one tightly constrained parameter, the
size of the asphaltene cluster. The fitted data gives a size of 5.2
nm, which is a very close match to the nominal 5.0 nm cluster
size, as previously shown in Fig. 1. Moreover, traditional modeling finds almost no asphaltene gradient because of the lack of
any GOR gradient. That is, traditional fluid modeling of the
mobile heavy oil fails miserably and here it is all but useless.
Asphaltene data from eight wells around the entire circumference of the field is shown in Fig. 5 (and includes the data
from Fig. 4). The fit is very good, indicating that the simple
Boltzmann distribution of asphaltene clusters accounts for the
huge increase in asphaltene content in the height of the mobile
heavy oil section for the entire circumference of the anticline.
The FHZ EoS with the Yen-Mullins model represents a dramatic improvement in the understanding of mobile heavy oil
columns. Moreover, the measured size of the asphaltene cluster
closely matches that found in an Ecuador heavy oil column
(5.0 nm)4 and in a Gulf of Mexico heavy oil column (5.2 nm)12.
Figure 5 also provides dramatic confirmation that asphaltene
clusters are in thermodynamic equilibrium, as given by the
62
Fig. 4. A local section of a large anticline with fluid data from three wells. Top:
The asphaltene content vs. height agrees exactly with a simple equilibrium model
with only one tightly constrained parameter, the size of the asphaltene cluster, here
determined to be 5.2 nm, closely matching the nominal 5.0 nm cluster size in Fig.
1. Bottom: The viscosity matches a simple Pal-Rhodes model, showing that
viscosity is largely exponentially dependent on asphaltene content.
Fig. 5. Data from eight wells shows that the mobile heavy oil column around the
entire circumference of the field matches the simple gravity term of the FHZ EoS
with one tightly constrained parameter, the asphaltene cluster size (here 5.2 nm vs.
the nominal 5.0 nm in Fig. 1). Moreover, the large height of the column yields a
factor-of-6 variation of asphaltene content. This field represents an extreme test of
our simple model for mobile heavy oil – and represents the best data set there is
(to the knowledge of the authors) to test thermodynamic modeling of mobile
heavy oil.
FHZ EoS. This indicates that this reservoir is in flow communication — that is, it is a connected reservoir13. Gross differences in asphaltene concentration in crude oil vs. height at
different reservoir locations could trigger convection, which
would then rapidly smooth out these differences. In addition, it
62884araD9R1_ASC026 3/15/13 11:41 PM Page 5
is plausible that distal parts of the field underwent similar
gravitation accumulations of asphaltene to arrive at current
observations of substantial uniformity around the flank. Asphaltene migration through reservoirs is a subject of current
research, and the consequence of this migration is seen repeatedly.
Above the mobile heavy oil section, there is less data. The
asphaltene content of the highest samples here is only a few
percent. It is known that the oil in the crest, at a much greater
height in the column, is black oil. At the asphaltene concentration of a few percent (in this oil) is found the point of transition from asphaltene cluster to asphaltene nanoaggregate. At
concentrations lower than a few percent asphaltene, the asphaltenes are dispersed as nanoaggregates. We saw in Fig. 3
that the gradient of nanoaggregates is not so great. Even at
much greater heights in this oil column, the oil remains black
oil. If asphaltenes were still within clusters even at low concentrations, then the huge reduction of asphaltene concentration
with height would continue until there would be almost no asphaltenes, as previously shown in Fig. 3. In other words, if the
huge gradient of asphaltene concentration with height, which
holds for clusters, continued throughout the entire height of
the oil column, then there would be a condensate (no asphaltenes) practically on top of the mobile heavy oil section.
This is not correct, and is resolved by postulating asphaltenes
as being present as nanoaggregates at lower concentrations —
thereby yielding much smaller gradients (cf. Fig. 3).
A critical component of the model of gravitation accumulation of asphaltenes is that the ratios of other saturates, aromatics, resins and asphaltenes (SARA) components are not
changing or are changing at a rate an order of magnitude
slower than the asphaltenes.
There is significant scatter in the SARA data, which is not
that unusual. Nevertheless, the trends are clear; the primary
variation in the mobile heavy oil samples is their asphaltene
content. The variations of ratios of other SARA fractions are
five to 10 times smaller. Indeed, if any other fraction were to
associate with asphaltenes, one would expect that to be resins.
But, clearly, bulk resins are not accompanying asphaltenes.
This limits an age old model showing strong asphaltene resin
association. Figure 6 shows that bulk resins do not associate
with asphaltenes. Indeed, very similar results were obtained in
a lab centrifugation experiment of live black oil.
Figure 7 shows the results from centrifugation of live black
oil14. This oil had a GOR of 800 scf/bbl, so both the solubility
term and the gravity term contribute to establishing the asphaltene and resin gradients. It took one month without seal loss to
achieve equilibrium in this spin. The asphaltene gradient is
~10x, while the resin gradient is 25% relative. Therefore, bulk
resins are not migrating with the asphaltenes. Analysis of the
centrifugation results did conclude that a fraction of the heaviest resins do associate with the asphaltenes. The picture that
emerges is that there is a molecular continuum going from
resins to asphaltenes. The criterion of n-heptane insolubility to
define the asphaltenes captures most but not all of the crude
Fig. 6. For the mobile heavy oils plotted in Fig. 5, the primary variation is the
asphaltene content. The variation of the other SARA fractions is a factor of 5 to
10 smaller. This data shows consistency with the finding of a simple gravitational
equilibration of asphaltene clusters through the height and circumference of the
field.
Fig. 7. Live black oil centrifugation shows a similar result to that found in Fig.
614. A giant asphaltene gradient (10x) was formed by centrifuging a live black oil
with moderate GOR so both the gravity term and the solubility term contribute to
the asphaltene gradient. Due to the lower asphaltene fraction in this black oil, the
asphaltenes are present as nanoaggregates.
oil fraction that self-assembles into aggregates (cf. Fig. 1)14.
The field data presented in Figs. 5 and 6 is consistent with the
centrifugation data of Fig. 7. The asphaltenes by far dominate
the fraction of crude oil that self-assembles. Moreover, mobile
heavy oils, such as those found in this study, have large asphaltene fractions that are all in asphaltene clusters. These clusters
equilibrate in the gravitational field, yielding large gradients
(cf. Fig. 5).
Tar Mat
At the base of the mobile heavy oil section, Fig. 5 indicates that
a tar mat was found. Several wells were drilled to intersect this
tar mat for characterization. The organics were extracted from
core sections at different depths in the tar mat and characterized
in terms of SARA fractions. Figure 8 shows an example of the
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asphaltene content in the extracted tar vs. depth for two separate wells at the same depth scale.
Figure 8 also shows that there is a nearly random variation
of tar with height in each of the two “tar” wells. The asphaltenes are not equilibrated vs. height, even in a single well,
which is a huge contrast to the heavy oil sections where the asphaltene content is (or appears to be) largely equilibrated over
the circumference of the mobile heavy oil flank. Figure 8 also
shows that there is no correlation of asphaltene concentration
laterally for these two wells. The asphaltene content shows
large increases and decreases over very short vertical distances.
The mobile heavy oil section was shown to be characterized
by a simple gravitational accumulation and equilibration of asphaltene vs. depth. Figure 8, on the other hand, shows that the
asphaltene content of the tar is not even monotonic with depth
and does not even approximate any equilibration. It is important to check whether the tar is simply an accumulation of asphaltene in oil or whether other SARA fractions show large
variations in the tar as well.
According to Fig. 8, there is a huge variation of asphaltene
content in the tar. Since the asphaltene content shows large
variations, the other SARA fractions must also show variations; the sum of all SARA fractions must add to 1. Therefore,
it is the ratio of the other SARA fractions that is of interest.
Figure 9 shows the ratios of asphaltenes to paraffins, aromatics to paraffins and resins to paraffins. By far the largest
change is in the asphaltene-to-paraffin ratio. That is, the tar is
primarily an addition of a variable amount of asphaltene to an
oil with fixed ratios of paraffins (or saturates), aromatics and
resins.
Figure 9 also shows that the tar is dominated by changes in
asphaltene content. Indeed, the variation of the asphaltene
content is enormous, in one well changing from ~30% to
65%. This picture is consistent with the origin of tar in this
field as being due to the gravitational accumulation of asphaltene at the base of the oil column, and it is consistent with the
same conclusion drawn for the origin of the mobile heavy oil
column immediately above the tar column. The primary differ-
Fig. 8. Asphaltene content vs. depth for tar wells below the mobile heavy oil
section in two wells (cf. Fig. 5). The asphaltene content does not vary
monotonically, even in a single well. In addition, there is no lateral correlation of
asphaltene content, in contrast to the mobile heavy oil sections. In the tar mat,
there are large increases and decreases of asphaltene within very small intervals of
height.
64
ences between the tar and the mobile heavy oil is that: (1) the
mobile heavy oils have asphaltene content less than ~30% (cf.
Fig. 8), while the tar has asphaltene content greater than
~30%, and (2) the mobile heavy oil is vertically and laterally
equilibrated, while the tar is not equilibrated even over short
vertical distances, let alone large lateral distances. Two factors
play an important role in equilibration: distance and viscosity.
Figure 10 shows the viscosity as a function of asphaltene content in an oil phase of fixed composition15. This viscosity profile
is not that of the oil and tar presented in this article, but nevertheless shows the dependence of viscosity on asphaltene content.
Figure 10 provides a plausible reason why the tar is not
equilibrated, while the mobile heavy oil directly above the tar
is equilibrated. (“Equilibrated” here means that the asphaltene
content is varying monotonically vs. depth according to Eq. 2.)
By showing that the viscosity is high at 30% asphaltene
content, and that every 5% increase in asphaltene content is
Fig. 9. The SARA fractions are divided by paraffins vs. asphaltene content for
samples from two “tar” wells (saturates = paraffins). By far the largest variation is
in the asphaltene/paraffin ratio; the aromatic/paraffin ratio and the resin/paraffin
ratio exhibit much smaller changes. Consequently, the tar can largely be described
as having large, variable asphaltene content in an oil of fixed composition.
Fig. 10. Viscosity is shown to depend exponentially (or more) on asphaltene
content for several different carbonaceous systems15. For the range of %
asphaltene relevant to the mobile heavy oil and tar sections of the hydrocarbon
column, the viscosity in this figure increases by a factor of 100,000,000. Note the
hydrocarbon system is not the crude oil and tar column from this field, but the
dependence of viscosity on asphaltene is similar.
62884araD9R1_ASC026 3/15/13 11:41 PM Page 7
associated with another huge increase in viscosity, Fig. 10 indicates that the viscosity in sections of the tar mat is extraordinarily high, precluding equilibration.
Plausible Geoscenarios Matching Field Observation
This Jurassic reservoir initially contained black oil. A subsequent charge of a lighter hydrocarbon could have occurred
because, in a normal burial sequence, the kerogen generates
lighter hydrocarbons with longer times and greater temperatures. The lighter hydrocarbon often goes to the top of the
reservoir without good mixing16. This lighter hydrocarbon (it
could even be gas) can diffuse into the oil column, causing
instability of the asphaltene17, 18. If the instability is not too
great, the asphaltenes can migrate great distances in the reservoir, in some cases going to the base of the reservoir. High concentrations of asphaltenes at or near the OWC can therefore
occur. One can imagine separate destabilizing events yielding
pulses of asphaltenes, all snowing down towards the OWC. At
high asphaltene concentrations, the viscosity increases, and if
the viscosity increase is also associated with a permeability restriction in the reservoir, then low viscosity tar can become
trapped or “perched” below the high viscosity tar. At some
high asphaltene concentrations, there might also be a phase
transition, yielding a phase very rich in asphaltenes that might
block pore throats. This is under investigation. If this occurs, it
represents a second mechanism that can cause lower viscosity
tar to be trapped underneath higher viscosity tar. For asphaltene concentrations below 30%, the viscosity is sufficiently
low that diffusion enables equilibration of the asphaltene in
the mobile heavy oil section.
CONCLUSIONS
Traditional EoS modeling of heavy oils has failed miserably
due to: (1) the previous lack of knowledge about asphaltene
colloidal sizes, and (2) the lack of a proper model to treat colloidal solids in crude oil. The Yen-Mullins model of asphaltene
nanoscience specifies the size of three distinct species of asphaltenes: molecules, nanoaggregates and clusters. This
nanoscience model enables accounting for the effects of gravity, which has been incorporated into the FHZ EoS for asphaltene gradients. Moreover, for mobile heavy oils, only the
gravity term contributes significantly to asphaltene gradients.
In a field in Saudi Arabia, a mobile heavy oil rim has been fit
to the model using a simple exponential equation (the Boltzmann distribution). Moreover, the asphaltene content varies by
a factor of six within this height. The simple Boltzmann distribution of asphaltene clusters accounts for this entire volume of
mobile heavy oil. SARA analysis of the crude oil confirms that
the mobile heavy oil column simply has added asphaltene into
a crude oil of fixed composition. A tar mat below the mobile
heavy oil does not show a monotonic increase of asphaltenes
towards the base. This is linked to the extraordinarily high
viscosities within the tar mat. SARA analysis of the tar establishes that, similar to the mobile heavy oil, there is variable
asphaltene added to a crude oil of fixed composition.
Gravitational accumulation of asphaltenes at the low points of
the reservoir is consistent with all observations. The application
of new asphaltene science to heavy oils is seen to greatly improve
the understanding and prediction of reservoir observations.
ACKNOWLEDGMENTS
U.A.E., November 11-14, 2012.
REFERENCES
1. Mullins, O.C.: “The Modified Yen Model,” Energy &
Fuels, Vol. 24, No. 4, January 19, 2010, pp. 2,179-2,207.
2. Mullins, O.C., Sabbah, H., Eyssautier, J., Pomerantz, A.E.,
Barré, L., Andrews, A.B., et al.: “Advances in Asphaltene
Science and the Yen-Mullins Model,” Energy & Fuels, Vol.
26, No. 7, April 18, 2012.
3. Freed, D., Mullins, O.C. and Zuo, J.Y.: “Theoretical
Treatment of Asphaltene Gradients in the Presence of GOR
Gradients,” Energy & Fuels, Vol. 24, No. 7, June 3, 2010,
pp. 3,942-3,949.
4. Pastor, W., Garcia, G., Zuo, J.Y., Hulme, R., Goddyn, X.
and Mullins, O.C.: “Measurement and EoS Modeling of
Large Compositional Gradients in Heavy Oils,” SPWLA
paper, presented at the 53rd Annual Logging Symposium,
Cartagena, Colombia, June 16-20, 2012.
5. Betancourt, S.S., Dubost, F.X., Mullins, O.C., Cribbs,
M.E., Creek, J.L. and Mathews, S.G.: “Predicting
Downhole Fluid Analysis Logs to Investigate Reservoir
Connectivity,” IPTC paper 11488, presented at the
International Petroleum Technology Conference, Dubai,
U.A.E., December 4-6, 2007.
6. Elshahawi, H., Shyamalan, R., Zuo, J.Y., Mullins, O.C.,
Dong, C. and Zhang, D.: “Advanced Reservoir Evaluation
Using Downhole Fluid Analysis and Asphaltene FloryHuggins-Zuo Equation of State,” paper prepared for the
53rd Annual Logging Symposium, Cartagena, Colombia,
June 16-20, 2012.
7. Mullins, O.C., Sheu, E.Y., Hammami, A. and Marshall,
A.G., eds.: Asphaltenes, Heavy Oils and Petroleomics, New
York: Springer, 2007.
8. Sabbah, H., Morrow, A.L., Pomerantz, A.E. and Zare,
R.N.: “Evidence for Island Structures as the Dominant
Architecture of Asphaltenes,” Energy & Fuels, Vol. 25,
No. 4, March 8, 2011, pp. 1,597-1,604.
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9. Buckley, J.S., Wang, J. and Creek, J.L.: “Solubility of the
Least-Soluble Asphaltenes,” in Asphaltenes, Heavy Oils
and Petroleomics, eds. O.C. Mullins, E.Y. Sheu, A.
Hammami and A.G. Marshall, New York: Springer, 2007.
10. Zuo, J.Y., Mullins, O.C., Freed, D. and Zhang, D.: “A
Simple Relation between Solubility Parameters and
Densities of Live Reservoir Fluids,” Journal of Chemical
and Engineering Data, Vol. 55, No. 9, May 4, 2010, pp.
2,964-2,969.
11. Mullins, O.C., Seifert, D.J., Zuo, J.Y., Zeybek, M.,
Zhang, D. and Pomerantz, A.E.: “Asphaltene Gradients
and Tar Mat Formation in Oil Reservoirs,” WHOC12182 paper, presented at the World Heavy Oil Conference,
Aberdeen, Scotland, September 10-13, 2012.
12. Nagarajan, N.R., Dong, C., Mullins, O.C. and
Honarpour, M.M.: “Challenges of Heavy Oil Fluid
Sampling and Characterization,” SPE paper 158450,
Exhibition, San Antonio, Texas, October 8-10, 2012.
13. Pfeiffer, T., Reza, Z., Schechter, D.S., McCain, W.D. and
Mullins, O.C.: “Fluid Composition Equilibrium; A Proxy
for Reservoir Connectivity,” SPE paper 145703, presented
at the SPE Offshore Europe Oil and Gas Conference and
Exhibition, Aberdeen, Scotland, September 6-8, 2011.
14. Indo, K., Ratulowski, J., Dindoruk, B., Gao, J., Zuo, J.Y.
and Mullins, O.C.: “Asphaltene Nanoaggregates
Measured in a Live Crude Oil by Centrifugation,” Energy
& Fuels, Vol. 23, No. 9, August 7, 2009, pp. 4,460-4,469.
15. Lin, M.S., Lumsford, K.M., Glover, C.J., Davison, R.R.
and Bullin, J.A.: “The Effects of Asphaltenes on the
Chemical and Physical Characteristics of Asphalt,” in
Asphaltenes: Fundamentals and Applications, eds. E.Y.
Sheu and O.C. Mullins, New York: Plenum Press, 1995,
pp. 155-76.
16. Stainforth, J.G.: “New Insights into Reservoir Filling and
Mixing Processes,” in Understanding Petroleum
Reservoirs: Toward an Integrated Reservoir Engineering
and Geochemical Approach, eds. J.M. Cubit, W.A.
England and S. Larter, Special Publication, London:
Geological Society, 2004.
17. Elshahawi, H., Latifzai, A.S., Dong, C., Zuo, J.Y. and
Mullins, O.C.: “Understanding Reservoir Architecture
Using Downhole Fluid Analysis and Asphaltene Science,”
SPWLA-FF paper, presented at the 52nd Annual Logging
Symposium, Colorado Springs, Colorado, May 14-18, 2011.
18. Zuo, J.Y., Elshahawi, H., Dong, C., Latifzai, A.S., Zhang,
D. and Mullins, O.C.: “DFA Asphaltene Gradients for
Assessing Connectivity in Reservoirs under Active Gas
Charging,” SPE paper 145438, presented at the SPE
Annual Technical Conference and Exhibition, Denver,
Colorado, October 30-November 2, 2011.
66
BIOGRAPHIES
Douglas J. Seifert is a Petrophysical
Consultant with Saudi Aramco, where
he works as the Petrophysics
Professional Development Advisor in
the Upstream Professional
Development Center (UPDC). Doug
specializes in real-time petrophysical
applications and fluid analysis. Before joining Saudi
Aramco in 2001, he was the Western Hemisphere Regional
Petrophysicist for Pathfinder Energy Services in Houston,
TX, and the Eastern Hemisphere Regional Petrophysicist in
Stavanger, Norway. Doug also worked as the Senior
Petrophysicist for Mærsk Olie og Gas in Denmark; for
Halliburton Energy Services in various operational,
research and technical support functions; and for Texaco in
their Technical Services and Production Operations.
Doug is the President of the Saudi Petrophysical Society,
the Saudi Arabian Chapter of the Society of Petrophysicists
and Well Log Analysts (SPWLA), and he also serves on the
SPWLA Technology Committee.
He received a B.S. degree in Statistics and a M.S. degree
in Geology, both from the University of Akron, Akron,
OH.
Dr. Oliver C. Mullins is a Science
Advisor to Executive Management in
Schlumberger. He is the primary
originator of downhole fluid analysis
for formation evaluation. For this, he
has won several awards, including the
Society of Petroleum Engineers (SPE)
Distinguished Membership Award and the Society of
Petrophysicists and Well Log Analysts (SPWLA)
Distinguished Technical Achievement Award; Oliver also
has been a Distinguished Lecturer four times for the
SPWLA and SPE.
He authored the book The Physics of Reservoir Fluids:
Discovery through Downhole Fluid Analysis, which won
two Awards of Excellence. Oliver has also co-edited three
books and coauthored nine chapters on asphaltenes. He
has coauthored >190 publications and has ~3,100
literature citations. Oliver has co-invented 80 allowed U.S.
patents. He is a fellow of two professional societies and is
Adjunct Professor of Petroleum Engineering at Texas A&M
University. Oliver also leads an active research group in
petroleum science.
Dr. Murat Zeybek is a Schlumberger
Reservoir Engineering Advisor and
Reservoir and Production Domain
Champion for the Middle East area.
He works on analysis/interpretation of
wireline formation testers, pressure
transient analysis, numerical modeling
of fluid flow, water control, production logging and
reservoir monitoring.
He is a technical review committee member for the
Society of Petroleum Engineers (SPE) journal Reservoir
62884araD9R1_ASC026 3/15/13 11:41 PM Page 9
Evaluation and Engineering. Murat also served as a
committee member for the SPE Annual Technical
Conference and Exhibition, 1999-2001. He has been a
discussion leader and a committee member in a number of
SPE Applied Technology Workshops (ATWs), including a
technical committee member for the SPE Saudi Technical
Symposium, and he is a global mentor in Schlumberger.
Murat received his B.S. degree from the Technical
University of Istanbul, Istanbul, Turkey, and his M.S.
degree in 1985 and Ph.D. degree in 1991, both from the
University of Southern California, Los Angeles, CA, all in
Petroleum Engineering.
Dr. Chengli Dong is a Senior Fluid
Properties Specialist in the Shell
FEAST team (Fluid Evaluation and
Sampling Technologies), and
previously he was a Schlumberger
Reservoir Domain Champion. Chengli
has been a key contributor on the
development of downhole fluid analysis (DFA) as well as
DFA applications in reservoir characterization. He
conducted extensive spectroscopic studies on live crude oils
and gases, and led the development of interpretation
algorithms on the DFA tools. In addition, Chengli has
extensive field experience in design, implementation and
analysis of formation testing jobs.
He has published more than 50 technical papers, and he
co-invented 10 granted U.S. patents and nine patent
applications.
Chengli received his B.S. degree in Chemistry from
Beijing University, Beijing, China, and his Ph.D. degree in
Petroleum Engineering from the University of Texas at
Austin, Austin, Texas.
Dr. Julian Y. Zuo is currently a
Scientific Advisor in Reservoir
Engineering at the Schlumberger
Houston Pressure and Sampling
Center. He has been working in the oil
and gas industry since 1989. Recently,
Julian has been leading the effort to
develop and apply the industry’s first simple Flory-HugginsZuo equation of state (EOS) for predicting compositional
and asphaltene gradients to address a variety of major oil
field concerns such as reservoir connectivity, tar mat
formation, asphaltene instability, flow assurance,
nonequilibrium with late gas charging, etc.
He has coauthored more than 140 technical papers in
peer-reviewed journals, conferences and workshops.
Julian received his Ph.D. degree in Chemical Engineering
from the China University of Petroleum, Beijing, China.
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Cementing Abnormally Over-pressurized
Formations in Saudi Arabia
Authors: Abdulla F. Al-Dossary and Scott S. Jennings
ABSTRACT
Cementing is one of the most important and crucial issues in
oil fields, especially for high-pressure and gas bearing formations. It is difficult to achieve a good zonal isolation in such
formation types because pressure is abnormal and formation
fluid contains corrosive fluids and gases. A common problem
associated with highly over-pressurized zones is cross flow
after cementing. Fluid flow from an over-pressured zone to a
low-pressure, high permeability zone can lead to deterioration
of the existing production hardware. Workover operations that
attempt to repair cement voids, including perforation, squeezing and use of casing patches or scab liners, are not recommended as they do not provide long-lasting results.
One onshore field in Saudi Arabia has experienced a persistent problem related to cementing at high-pressure zones. Recently, communication between Formation-A (an abnormally
over-pressurized zone) and Formation-B (a low-pressure zone)
is occurring with increasing frequency due to long-term seawater injection, which has resulted in production interruption in
several wells. This article addresses the problems by investigating field practices that include drilling, cementing and completion. It also reviews the field reports and cased hole logs for
the affected wells. Three-month and six-month studies were
conducted to evaluate the effects of Formation-A water on cement, where the cement was exposed to Formation-A water
under downhole conditions. Tests for mechanical properties,
including permeability, a thermogravimetric analysis (TGA)
and tests using energy dispersive X-ray fluorescence (EDXRF)
are presented, in addition to discussions of some of the preliminary findings.
INTRODUCTION
Cement channeling is viewed as one of the major completion
issues in the petroleum industry. Several attempts have been
made by cementing companies and individual researchers to
tackle this problem; however, so far there is no reputable improvement. Fluid migration in cement happens in the course of
spotting cement or afterwards. The main cause of gas channeling is believed to be the inability of cement to maintain enough
pressure on the formation before it sets1. Fluid migration
68
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through wall cake is accredited to the failure of cement to
make a good bond to the formation2. There are several factors
that directly affect this phenomenon, including the type of cement used, chemical additives, mud and cement density, temperature, pressure, mud cake film, centralization, movement of
casing string and reciprocation while pumping the cement
slurry and cement filtrate3.
Most of the theories have been developed to address problems associated with cement channeling that leads to severe
loss in the hydrostatic pressure of the cement column during
gelation (i.e., when cement passes from liquid to a solid state).
Most of the suggested solutions in the past have focused on
one property of the cement but neglected the change in other
properties, assuming that changes that may be directly responsible for the gas migration occur only for some of the physical
or chemical properties. Casing centralization, use of a
scratcher to clean mud cakes and use of fluid spacers are some
of the solutions implemented to help improve zonal isolation4.
The cement is capable of transmitting pressure as long as it
is in the liquid state until it attains gel strength — enough to
form an effective seal5. Upon cement placement, cement suffers
a gradual drop in hydrostatic pressure, following a downward
gradient until it reaches that of water. Hydrostatic pressure
will further drop and become less than that of water during
gelation due to dehydration within the cement matrix and fluid
loss. Excessive dehydration rates and fluid loss will cause high
shrinkage that might form a passage for formation fluids to
transfer from a high-pressure zone into a low-pressure zone
and into the well through filter cake or casing leak6. Cooke7
studied the pressure behavior during the first six hours after
pumping cement and observed that cement loses pressure at 39
psi/ft. Also, he found that application of annular pressure can
make up for the drop, maintaining the pressure required to
overbalance the formation until the cement develops enough
compressive strength for effective zonal isolation.
Gas or fluid migration will not take place if the cement is
able to develop gel strength between 500 lbf/100 ft2 within 15
minutes after the start of transition time8. It would be impossible for gas to migrate at 500 lbf/100 ft2, especially if the cement has low permeability, zero free water, high gel strength,
low viscosity and a short transition time. In such situations,
gas will enter into the cement matrix and create channels
62884araD10R1_ASC026 3/15/13 11:42 PM Page 2
within the cement. Sometimes it overcomes the tensile strength
of the cement structure, breaks the cement matrix and travels
through the micro-fractures. It is assumed that the hydrostatic
pressure of the cement column will decrease when the gas bubbles are already inside and that the gas will try to expand until
the pressure difference is large enough to overcome the cement
tensile strength and in turn break the cement9, 10.
On the other hand, water does not migrate in the same
manner as gas since it is not compressible11. There is no way
for liquid, i.e., water or oil, to travel up or down the cement
column unless there are channels big enough within the cement
for it to flow through. Such channels possibly can form after
gas migration, when the channels get wider and wider due to
the high-pressure/high temperature (HP/HT) environment12.
During cementing at an over-pressurized zone, the formation
might be underbalanced before the cement becomes strong in
the sense that it resists fluid movement. If this happens, formation fluid will displace or squeeze cement into the formations
above or below the high permeability zone, eventually resulting in a non-cemented pipe.
Improper drilling practices also contribute to poor cementing to some extent. For instance, drilling with mud that leads
to uncontrolled fluid loss leaves excessive filter cake that is difficult to remove. It has become evident that filter cake gives up
at 2 psi13. Also, high mud weight along with high circulation
rate while drilling through high permeability zones or a lowpressure, highly porous formation encourages fractures and
wash outs to develop, which are difficult to cement. Hole conditioning practices are vital to a successful primary cementing
job. The hole should be clear of fill and filter cake, and in
gauge before cementing; therefore, a clean out trip with a hole
opener is required to further clean the hole by removing any
remaining filter cake and gelled mud. Other means, like use of
low viscosity mud and high circulation rate, will help effectively remove wall cake and mud pockets14. Mud buckets,
which emerge when mud remains static a long time in the hole
with formation cuttings inside, provide a route for fluid after
they dehydrate.
It is very challenging to have an effectively cemented pipe in
highly deviated and horizontal holes. A couple of factors that
play an important role in cementing such wells include centralizing, mud displacement efficiency and hole cleaning. It is wellknown from past research that fluid tends to flow more in a
wide side offering least resistance than in a low side that restricts flow15. To overcome this problem, the number of centralizers needs to be selected in a way that improves standoff
without increasing drag, which might present additional problems. Also, the design or shape of the centralizers should be
optimized in a way that helps provide a uniform flow regime
around the pipe and improve the displacement efficiency ratio.
A spacer volume that provides a four-minute contact time with
the hole and the use of low viscosity mud at a circulation rate
of 3 barrels per minute (bpm) will improve filter cake removal
efficiency according to field and lab results. Moreover, the
spacer should be compatible with cement, as well as lighter
than the cement and heavier than the mud in the hole, to improve displacement efficiency and avoid mud channeling and
cement contamination.
During the life of the well, the cement sheath is vulnerable
to failure when different events take place, such as stimulation,
well testing, communication testing, casing pressure tests and
cement squeeze jobs, which generate thermal and cyclic
stresses as a result of changes in hydrostatic pressure and temperature16. Mechanical stresses generated by tubular run in
holes also contribute to cement fracture in the long term. Cement contracts and expands frequently in response to temperature changes, and if this movement exceeds the cement tensile
strength, cement will fracture. Radial expansion of the cementcasing interface, due to high-pressure induced stresses, will
radically compress the cement and induce tensile tangential
stress that can cause a crack. When that happens, the tensile
strength of the cracked section will drop to zero, and the distribution of stress in the cement will be changed. This change will
help the cracks creep outward and eventually reach the casing
formation interface. If the crack occurs across the long axial
distance, a channel will form through which liquid can flow17.
Cement deterioration can accelerate in the presence of corrosive CO2 gas. The effect of CO2 is much worse in HP/HT
formations. In such an environment, cement degradation due
to carbonation will occur in a short time. Three different
chemical reactions occur when cement comes in contact with
CO2:
• Formation of Carbonic Acid (H2CO3): It lowers pH. Its
effect depends on temperature, partial CO pressure and
other ions dissolved in the water.
• Carbonation of Cement or Cement Hydrates: It causes
an increase in density, which leads to the increased
hardness and decreased permeability of the cement
sheath. As a result, CO2 diffusion will decrease and
volume will increase by up to 6%. In such cases, cracks
will develop.
• Dissolution of CaCO3: This phenomenon happens in
the presence of water containing CO2 for a long period
of time. Effects of this reaction include an increase in
permeability and porosity and a loss of mechanical
integrity. This dissolution process will lead to poor
formation isolation.
It is still in dispute whether or not carbonation is detrimental to cement integrity. Some researchers showed that the mechanical properties of cement will suffer degradation due CO2
exposure, leading to fluid migration. On the other hand, some
studies conducted on 20- to 30-year old cement samples from
CO2 wells showed that they maintained their integrity despite
carbonation. Cement mainly consists of tricalcium silicate
(C3S) and dicalcium silicate (C2S). When cement reacts with
water, calcium silicate hydrate (C-S-H) and calcium hydroxide
(Ca2) evolves. During exposure to CO2 dissolved in water,
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calcium carbonate (CaCO3) will form. This product is harmful
to cement sheaths at high concentrations because it cracks cement. There are two solutions to minimize the carbonation effect and prolong the life of cement18-20:
• Reduce the cement permeability so that it withstands
well operations with low dehydration volume shrinkage.
• Optimize the cement design so that dehydration
products have fewer materials that are reactive with
CO2.
Cement mechanical properties, including compressive
strength, yield stress, permeability, Young’s modulus and Poisson’s ratio, should be taken into account when designing a
cement system to guarantee that the cement will survive longer
when exposed to cyclic loads. Physical properties like thickening
time, fluid loss and viscosity also must be considered carefully to
help reduce transition time and achieve the required compressive strength as quickly as possible. Cement that is mechanically,
thermally and chemically stable will be able to survive HP/HT
and corrosive environments.
COMMUNICATION PROBLEM BETWEEN FORMATIONS
A AND B
the two formations. As an undesirable consequence, Formation-B injectors are feeding Formation-A along with Formation-B. In addition, high injection volumes and velocities have
eroded the Formation-B anhydrite cap rock and established a
communication between the reservoirs. Formation-A pressure
is higher only in the central area. Formation-B pressure at the
flanks is higher than Formation-A pressure due to peripheral
injection. Formation-B pressure declines at the center because
of oil production; however, because Formation-A does not
have any production, Formation-A pressure builds up continuously in the center.
FIELD PRACTICES
A survey was made of the field practices implemented in wells
where the communication problem arose, including drilling,
hole conditioning and cementing. In addition, the cement bond
log (CBL) was reviewed. Two wells were chosen for this study:
Well-A and Well-C. Well-A is a horizontal well, while Well-C is
vertical.
DRILLING
Well-A
A communication problem between Formations A and B
emerged recently in several newly drilled and sidetracked
wells. Three wells showed a recurrence of Formation-A casing
leak. This problem is a big concern, and quick intervention is
needed before it escalates and becomes a major issue. The
reason why the leak occurred has not been identified yet;
however, there are three possible explanations for how it developed. First, Formation-A water made its own way behind the
cement, through the mud cake and into the well, since Formation-A pressure is higher than the pressure of the productive
zone across Formation-B. Second, Formation-A gas transferred
through cement channels and reacted with the casing, which
means the casing got corroded and holes developed, paving the
way for Formation-A water to enter the wellbore and eventually kill the well. Third, water influx attacked the cement and
created a severe contamination because the cement hydrostatic
pressure was not enough to overbalance the Formation-A high
pressure, allowing communication to take place during weight
on cement (WOC).
Most of the wells with a casing leak problem across Formation-A were drilled in early 2006 to increase the oil production. Basically, these wells were completed as either vertical or
horizontal open hole wells with 7” liners across Formations A
and B. All wells were completed with 7” downhole packers
and 4½” tubing. Soon after the first completion, these wells
started producing Formation-A water, which was an indication
of communication between Formations A and B.
It is important to note that Formation-A has a higher pressure than that of Formation-B, which resulted from the poor
cement behind the pipe and the erosion of anhydrite between
70
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This well was drilled and completed as a Formation-B horizontal open hole producer in mid-2007. In this well, a 8½” curved
section (0° to 81°) was drilled from two formations above Formation-A all the way down to a 2 ft true vertical depth (TVD)
inside Formation-B with full circulation, Fig. 1. Mud weight
was 64 pounds per cubic foot (PCF) at the start until Formation-A was hit, at which point the well started flowing at 40
barrel per hour (BPH). The well was then shut-in until pressure
stabilized. The stabilized shut-in pressure was 450 psi. The
mud weight was increased to 84 PCF to kill Formation-A. After that, the rest of the hole was drilled to a 2 ft TVD below
the top of Formation-B. The hole was swept with a Hi/Low
Vis pill to effectively clean the well by improving cutting lifting
efficiency. In addition, a wiper trip was performed from the
bottom up to the 9⅝” casing shoe to boost the hole cleaning
efficiency before running the 7” liner.
Well-C
This well was drilled and completed as a Formation-B vertical
open hole producer in early 2006. In this well, an 8½” open
hole was drilled from two formations above Formation-A all
the way down to a 2 ft TVD inside Formation-B with full circulation, Fig. 2. Mud weight was 64 PCF at the start, until
Formation-A was hit, at which point the well started flowing
at 25 BPH with H2S traces. The mud weight was raised to 87
PCF to kill Formation-A. After that, the rest of the hole was
drilled to Formation-B. The hole was swept with a Hi/Low Vis
pill to effectively clean the well by improving cutting lifting
62884araD10R1_ASC026 3/15/13 11:42 PM Page 4
Fig. 1. The sketch for Well-A.
efficiency. In addition, a wiper trip was performed from the
bottom up to the 9⅝” casing shoe to boost hole cleaning efficiency before running the 7” liner.
The wells were placed on production in mid-2006 and early
2007, respectively. They both produced oil with zero water cut
for six months before being declared dead due to communication between Formations A and B, which was confirmed by
water sampling and a production logging tool log as well.
HOLE PREPARATION AND CEMENTING
In both wells, a 7” liner was run consisting of a float shoe,
float collar, landing collar, 7” casing joints and a mechanical
hanger along with a top packer and tie-back receptacle. Upon
reaching the bottom, the casing was rotated and reciprocated,
in addition to circulating the well at the highest possible rate,
to remove mud cake. Then the mechanical liner hanger was
set. After that, water spacer was pumped ahead of the cement
to remove any residual impurities and prevent any potential
cement contamination from contact with mud.
In Well-A, the 7” liner was centralized as follows:
• Every joint from the bottom until an inclination of 44°
and every second joint above that to the kickoff point
were centralized with a spiral centralizer.
Fig. 2. The sketch for Well-C.
Class G + 0.6% (Dispersant) + 0.3% (Fluid loss) + 0.05 gps
(Retarder) + 0.005 gps (Defoamer)
Slurry Weight
101 PCF
Thickening Time
5 - 5.5 hours
Table 1. Lead cement recipe
Class G + 1.2% (Dispersant) + 0.4% (Fluid loss) + 0.22%
Slurry Weight
118 PCF
Thickening Time
4 - 5 hours
Table 2. Tail cement recipe
• Every other joint was centralized with a collapsible
centralizer to the 9⅝” casing shoe, and after that every
third joint was centralized inside the casing to the 7”
liner hanger using a bow rigid centralizer.
In Well-C, the 7” liner was centralized as follows:
• The first five joints and then every second joint to the
9⅝” casing shoe were centralized with collapsible
centralizers.
• Every third joint was centralized inside the casing to the
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7” liner hanger using a bow rigid centralizer.
After centralization, the wells were cemented in two stages
using the cement recipes shown in Tables 1 and 2.
During cementing, no lost circulation was encountered in
either well. At the end, the excess cement was reversed out,
and the liner top packer was tested with water up to 2,000 psi,
with no leak detected.
A CBL log was run across the entire 7” liner and showed
poor cement across Formations A and B, which confirmed that
Formation-A water was dumping into Formation-B, Figs. 3
and 4.
debatable whether Formation-A sour conditions contributed to
the poor cement behind the liner that led to the communication problems or not. The effect of Formation-A water should
not be overlooked when rooting out the problem. But given
the results of tests to date, as described below, this study assumes that there is no effect of Formation-A water on cement.
EXPERIMENTAL WORK AND EQUIPMENT
A three month study was conducted to find out the degree to
which Formation-A water contributed to the communication
problem. In this study, cement was exposed to Formation-A
EFFECT OF FORMATION-A WATER ON CEMENT
The cement was placed in a harsh environment where the pressure reaches 4,000 psi and CO2 and H2S gases exist. It is still
Fig. 3. CBL for Well-A.
72
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Fig. 4. CBL for Well-C.
62884araD10R1_ASC026 3/15/13 11:43 PM Page 6
Initial Curing
Permeability CC/min
3 Months Raw Water Curing
3 Months Formation-A Water
Curing
Sample-13
Sample-14
Sample-19
Sample-110
Sample-115
Sample-116
0
0
0
0
0
0
Table 3. Permeability tests results after short-term exposure to Formation-A water
water for three months under molded downhole conditions,
Fig. 5. Formation-A water contains 4.5% CO2 gas and 1.28
ppm H2S gas. The same cement used in the wells was used to
prepare the cement samples. Some of the cement samples were
cured in raw water at 215 °F before being exposed to Formation-A water at 215 °F and 4,000 psi, Fig. 6. Parallel to that,
other cement samples were cured in raw water at the same
conditions. Upon completion of the curing process, all cement
samples were tested for mechanical properties, namely, permeability, compressive strength, Poisson’s ratio and Young’s
modulus. In addition, thermogravimetric analysis (TGA) and
energy dispersive X-ray fluorescence (EDXRF) tests were
conducted.
A well was drilled to collect the Formation-A water samples
needed in this project. After hitting Formation-A, the well was
flowed with a test packer isolating the zone until clean water
reached the surface. A total of 40 gallons of water was collected.
In total, 18 samples were prepared using the same cement
recipe used in the field. Cement samples were then poured in
different cubical and cylindrical molds. These molds were
placed in the curing chambers at 215 °F for two days. After
the curing period, the cement samples were removed and the
weight was recorded. Each test specimen was assigned a number. Four samples were tested for mechanical properties, including permeability, and subjected to TGA and EDXRF tests
after the initial curing. The remaining samples were divided
into two groups. The first set was cured under sour conditions
in Hastelloy metal autoclaves for three months, while the second set was cured in raw water in autoclaves for the same period of time. Samples cured for six months in sour conditions
in Formation-A water are shown in Fig. 7. At the end, the cement samples were taken out of the autoclaves and tested for
mechanical properties, including permeability, and subjected to
TGA and EDXRF tests.
Permeability Test
The permeability test is conducted using permeability equipment. It consists of a core holder in which the cement sample is
placed, a fluid cylinder for fluid injection, a beaker to collect
fluid, if any, a pump for injection purposes and a computer to
collect data. The sample is placed in the core holder after being
cleaned and trimmed. Then brine is injected into the cement
sample at 700 psi differential pressure and an injection rate of
2 cc/min. At the end, the amount of water collected is measured, Tables 3 and 4.
Fig. 5. Some cement samples after being exposed to Formation-A water for three
months.
Fig. 6. Some cement samples before being exposed to Formation-A water.
Fig. 7. Some cement samples after being exposed to Formation-A water for six
months.
Class G + 1.2% (Dispersant) + 0.4% (Fluid loss) + 0.22%
Slurry Weight
118 PCF
Thickening Time
4 - 5 hours
Table 4. Permeability tests results for long-term test
Young’s Modulus and Poisson’s Ratio Test
In the test conducted to calculate Poisson’s ratio, Young’s modulus and peak strength, axial stress is applied to a test specimen
until the cement starts to break or fracture. The cement samples
are cut into 3” length x 1.5” outer diameter size using the
trimming machine. Then the sample surfaces are finished or
ground using a surface grinding machine. The degree of
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62884araD10R1_ASC026 3/15/13 11:43 PM Page 7
6 Months Raw Water Curing
6 Months Formation-A Water Curing
Sample-117
Sample-118
Sample-125
Sample-126
10,944.9
11,548.6
12,656.7
13,093.8
Dynamic E, psi
1.809E+06
1.816E+06
2.005E+06
1.859E+06
Static E
3.084E+06
2.998E+06
2.904E+06
3.142E+06
Dynamic Y, psi
0.260
0.276
0.241
0.268
Static Y, psi
0.242
0.288
0.189
0.172
Compressive Strength, psi
Table 5. Mechanical properties for long-term test
parallelism of the surfaces of the sample is then measured. To
ensure the load is applied evenly over the surface, the accepted
tolerance should be equal to or less than 2/1,000”. The sample is
then placed inside the Tri-Axial equipment, which consists of a
core holder, a piston, a vessel, a control panel, a camera and a
computer for data acquisition. At first, a plastic jacket is used to
protect the plug while applying the confining pressure to avoid
fluid entry into the plug. After that, the core is placed into the
core holder. Three voltage linear differential transducer wires are
connected to the core holder. Two wires are used to measure
the axial distance change while the third one is for change
measurement in radial distance. Next, confining pressure is applied at 700 psi, and axial load ranging from 5 to 15 MPA is
applied to the piston at a temperature of 150 °C. Then Young’s
modulus, Poisson’s ratio and peak strength are calculated,
Table 5.
EDXRF Test
TGA Test
This test is conducted to measure the thermal stability and
composition of the cement as a function of time. The effect is
quantified by the weight loss that elements suffer due to heat.
First, the cement sample is crushed and milled until it becomes
a powder. Then a pellet is produced with 50 mg of cement and
placed into the TGA test apparatus. Then the temperature is
raised at a rate of 2 °C/min from room temperature until
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111
112
129
130
CaO
59.85
60.06
56.96
57.90
SiO2
19.65
19.71
17.58
17.93
Fe2O3
4.80
4.71
4.24
4.32
Al2O3
2.40
2.30
2.20
2.45
SO3
1.88
1.89
2.39
2.38
MgO
1.70
1.68
1.66
1.88
K2O
0.08
0.12
0.15
0.09
TiO2
0.22
0.20
0.20
0.21
Mn2O3
0.04
0.04
0.04
0.04
SrO
<0.05
<0.05
0.07
0.06
Table 6. Chemical composition for cement after long-term exposure Formation-A
water and raw water
In this test, samples are tested to determine the elemental compositions that make up the cement system. The cement sample
is crushed and milled until it becomes a powder. Then the
powder is mixed with 0.5 grams of a chemical binder. The
mixture is poured into a pellet mold before being pressed at 15
psi by the X-Press machine. The pellet is then placed inside a
spectrometer that consists of a 400 watt X-ray tube, a computer
controlled high voltage generator for the X-ray tube, liquid N2,
a cooled Si(Li) detector, a multichannel analyzer and a computer for data acquisition. The EDXRF analyzes the sample
for elemental composition after entering the weights of the
sample and binder, Table 6.
74
Approximate Weight Percentages
Compounds
Initial Curing
Sample#
Short-term
Water Curing
111
112
Short-term
CO2 Curing
116
115
117
118
Mass loss %
13.06
12.98
12.66 13.15 16.42 16.09
Residual
Mass % (1501,000 ºC)
74.21
73.57
76.57 74.12 77.59 77.57
LOL %
(20-150 ºC)
25.8
26.4
23.43 25.88 22.41 22.43
Table 7. TGA results after initial setting, water curing and Formation-A water curing
1,000 °C is reached. Data, including the amount of weight loss
and remaining mass percentage, are calculated by the computer, Table 7.
RESULTS AND DISCUSSION
Short-term Test
All samples were examined physically upon their removal from
the CO2 autoclave. All samples were inspected and were found
62884araD10R1_ASC026 3/15/13 11:43 PM Page 8
Initial Curing
3 Months Formation-A Water
Curing
3 Months Water Curing
Sample-11
Sample-12
Sample-17
Sample-18
Sample-113
Sample-114
8,609.1
10,024.8
11,587.7
12,030.6
11,279.9
12,270.0
Dynamic E, psi
2.949E+06
2.930E+06
2.994E+06
2.933E+06
3.025E+06
3.001E+06
Static E
7.153E+05
2.322E+06
2.177E+06
2.120E+06
1.958E+06
2.400E+06
Dynamic Y, psi
0.282
0.281
0.275
0.276
0.174
0.219
Static Y, psi
0.125
0.125
0.298
0.275
0.290
0.258
Compressive
Strength, psi
Table 8. Mechanical properties after short-term exposure to Formation-A water
Long-term Raw
Water Curing
Sample#
Long-term CO2
Curing
111
112
1,129
130
Mass Loss %
16.32
16.11
15.85
16.77
Residual Mass %
(150-1,000 °C)
79.09
79.49
79.59
78.62
LOL % (20-150 °C)
20.91
20.51
20.41
21.38
Table 9. TGA results after long-term water curing and Formation-A water curing
Fig. 8. TGA chart after initial curing.
to be intact. All samples were found to have turned to a black
color due to their reaction with the H2S gas. Mechanical properties, including permeability, Young’s modulus and Poisson’s
ratio, were all calculated before and after Formation-A water
exposure, Table 8. According to the permeability test, the cement stayed solid for 15 minutes during brine injection at a
pressure of 700 psi, indicating that it is impermeable. Also, results showed a slight change in the rest of the mechanical properties. For example, Static E increased from 2.322E+06 to
2.400E+06 psi, while Dynamic E increased from 2.930E+06 to
3.001E+06 psi. Tests also showed that Static Y increased after
exposure from 0.125 to 0.29, and that Dynamic Y increased
from 0.282 to 0.290. All results pertaining to the tests of mechanical properties, including permeability, for all samples are
in Tables 3 and 4.
The TGA analysis showed that the cement lost approximately 13% of mass due to moisture evaporation between 20
°C to 150 °C. The cement sample suffered a further weight
loss of 13% as the temperature rose to 1,000 °C due to the decay of some elements. The sample mass decreased by 26% in
total during the test. EDXRF results showed that the cement
samples after initial curing mainly consisted of CaO (60%)
and SiO2 (19%) by weight, Fig. 8. After curing in Formation-A
conditions, less than 1% change in mass occurred.
These findings showed that Formation-A water did not significantly harm the cement integrity even in the presence of
high pressure for the three month test period. This is most
likely due to the small amount of CO2 gas present in the curing
water. The picture will be clearer after the end of the six month
test period.
Long-term Test
According to the permeability test, the cement stayed solid for
15 minutes during brine injection at a pressure of 700 psi, indicating that it is impermeable. Also, results showed a slight
change in the rest of the mechanical properties. For example,
dynamic Young’s Modulus (E) increased from 1.089 E+06 to
2.005 E+06 psi while Static E increased from 2.998E+06 to
3.142E+06 psi. In regard with Poisson’s ratio (Y), tests showed
that Static Y decreased from 0.288 to 0.189 and Dynamic Y
decreased from 0.276 to 0.241, Table 5.
The TGA analysis showed that the cement lost approximately 4.61% of mass due to moisture evaporation between
0 °C to 150 °C. The cement sample suffered further weight
loss of 16.77% as the temperature rose to 1,000 °C due to the
decay of some elements, Table 9. The sample mass decreased
by 21.38% in total during the test. EDXRF results showed
that the cement samples after six months of curing mainly consisted of CaO (60% to 57%) and SiO2 (19.5% to 17.5%) by
weight, respectively, Tables 10 and 11. In addition, the weight
of these two elements decreased by 2% to 3% due to an encountered error while taking the WOC. No major change in
mass has been observed. Moreover, the cement color changed
from gray to black owing to the reaction with H2S gas.
These findings showed that Formation-A water did not harm
cement integrity even in the presence of high pressure. This is
due to the small amount of CO2 gas present in the curing water.
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62884araD10R1_ASC026 3/15/13 11:43 PM Page 9
Elements
8948 1-5
(Initial Curing)
8948 1-6
(Initial Curing)
CaO
60.12
60.30
SiO2
19.85
19.76
Fe2O3
4.52
4.54
Al2O3
2.68
2.74
SO3
1.89
1.88
MgO
1.87
1.93
K2O
0.43
0.46
TiO2
0.20
0.20
Mn2O3
0.04
0.05
SrO
0.04
0.04
Table 10. Chemical composition for cement after initial setting
Compounds
Short-term Formation-A Water
Short-term Water
Curing
CaO
58.89
59.32
60.92
60.88
SiO2
18.08
18.32
19.15
19.10
Fe2O3
4.37
4.38
4.59
4.57
Al2O3
2.5
2.54
2.52
2.51
SO3
2.53
2.49
1.94
1.94
MgO
1.9
1.86
1.76
1.79
K2O
0.19
0.17
0.06
0.05
TiO2
0.19
0.20
0.21
0.21
Mn2O3
0.04
0.04
0.04
0.04
SrO
0.06
0.06
0.04
0.04
Table 11. Chemical composition for cement after short-term Formation-A water
curing and raw water curing
After an extensive review of the field practices, it is clear
that the dominant factor contributing to communication between Formations A and B is the loss of hydrostatic pressure of
the cement column in addition to high Formation-A pressure.
No deficiencies were found in field cementing practices, including mixing and pumping the cement, conditioning the hole
prior to the cement job, mud cake removal, and mud displacement and casing centralization.
A batch mixer was used in all cement jobs as it gives an accurate density reading of the cement slurry. The number of
centralizers used in the horizontal wells was selected to obtain
70% standoff across critical open hole sections. According to
field findings, this degree of concentricity is fair enough for
76
SPRING 2013
good zonal isolation21. This supports the conclusion that centralization was not poor since the problem also occurred in
vertical wells where the standoff is as high as 95%. Liner rotation and reciprocation within 60 ft stroke, in addition to circulation at a rate of 4 bpm, helped clean filter cake and provide
uniform cement distribution around the casing. Conditioning
mud to reduce its viscosity improves mud displacement efficiency by enhancing fluid mobility. In addition, liner rotation
and reciprocation increases the mud’s ability to erode and
remove bypassed mud by reducing casing-to-mud and wellbore-to-mud drag forces. The presence of a spiral centralizer
improved the flow regime of cement across the horizontal sections. A compatible viscous spacer was used to separate the
cement and drilling fluid. The spacer helps avoid premature
setting of cement, cement channeling and cement contamination. The volume of the spacer was calculated to give a contact
time of 10 minutes, which is consistent with widely used cementing practices. The spacer density was higher than mud
and lighter than cement. This best practice in cementing helps
effectively displace mud and avoid mud bypassing cement.
The results of the survey of field practices were surprising
since they showed that all practices were perfect. Therefore, it
was advisable to go back to the literature and examine the
problem more deeply by focusing on the effect of a loss of hydraulic pressure while waiting on the cement to set and by ignoring the other factors after it was confirmed that they were
not linked to the problem completely. During the second look
at the literature, an interesting experiment conducted in the
field by Cooke7 to study the behavior of cement hydraulic
pressure during the first six hours after cement placement was
found. The results of this experiment showed that cement pressure decreases at 39 psi/ft during the first six hours after
pumping the cement. These results are supported by the experiment Levine2 conducted three years earlier that showed that
cement is able to transfer pressure during gelation time until
the cement gets set, after which the cement is not able to transmit pressure.
Such a finding was utilized along with field data to plot
pressure vs. depth charts to study the behavior of cement hydrostatic pressure while pumping cement and six hours later.
The red line up to the intersection point indicates the pressure
of the mud column, while the rest of it shows the pressure of
the cement and mud columns six hours following cement
placement. In contrast, the blue line shows the pressure of the
cement and mud columns right after cement placement. As
illustrated in Fig. 9, the hydrostatic pressure at the top of the
Formation-A pressure was 4,570 psi before it decreased to 700
psi below the Formation-A pressure, creating an underbalanced situation during which Formation-A water displaced cement into permeable zones above and below, leaving the liner
uncemented and allowing communication to take place while
waiting on the cement to set. As a result, communication was
established between these two zones.
Formation-A in this area has high reservoir pressure.
62884araD10R1_ASC026 3/15/13 11:43 PM Page 10
downward onto the annulus and formations below. This further encouraged the flow of influx from Formation-A into the
annulus. Use of 3,000 ft liner lap also contributed to the loss
of hydrostatic pressure, since the amount of loss in pressure is
higher there compared with a short cement column.
CONCLUSIONS
Fig. 9. Behavior of cement column pressure after 6 hours from cement placement
(Well-A).
1. The root cause of the communication problem was found
clearly to be the loss of hydrostatic pressure before the
cement attained enough compressive strength.
2. Cementing practices, including setting the liner top packer
and use of long liner laps, further encouraged water influx
to attack and contaminate the cement.
3. CBL logs showed poor cement and water channeling, confirming the occurrence of communication.
4. Lab results showed that Formation-A water is not detrimental
to cement during this period of time.
5. Solutions, including use of a short cement column, elimination of the liner to packer, application of annular pressure
and use of a zonal isolation packer between Formations A
and B, will help avoid cement contamination due to water
influx during WOC.
6. The CBL should be run immediately after the cement job so
that corrective measures can be taken in a timely manner.
7. Field practices showed no deficiencies except those previously
highlighted.
REFERENCES
Fig. 10. Behavior of cement column pressure after 6 hours from cement placement
(Well-C).
Therefore, it was easy for the cement column to be underbalanced against Formation-A before it was able to develop the
required static gel strength of 500 lbf/100 ft2. When the underbalance occurred, the inflow of water from Formation-A contaminated the cement column in the annulus. Actual reduction
in hydrostatic pressure experienced by a cement column is
dependent on the development of its gel strength and reduction
in the slurry volume. To illustrate the occurrence of water flow
from Formation-A during the primary cementing job in Wells
A and C, the pressure loss profile calculated from Cooke’s7
data was used. As shown in Figs. 9 and 10, the loss in the
hydrostatic pressure likely caused the cement column to be
underbalanced against Formation-A.
Figures 9 and 10 also demonstrate that in the first six hours
following the cement placement, the hydrostatic pressure of
the cement column dropped by 700 psi, creating an underbalanced situation and allowing for communication between formations. Without doubt, the main factor that caused poor
primary cementing across Formation-A behind the 7” liner is
loss of hydrostatic pressure in the cement column after it was
spotted in place in the annulus. In addition, setting a 7” liner
top packer had isolated the hydrostatic pressure from acting
1. Cheung, P.R. and Beirute, R.M.: “Gas Flow in Cements,”
Journal of Petroleum Technology, Vol. 37, No. 6, June
1985, pp. 1,041-1,048.
2. Levine, D.C., Thomas, E.W., Bezner, H.P. and Tolle, G.C.:
“Annular Gas Flow after Cementing: A Look at Practical
Solutions,” SPE paper 8255, presented at the SPE Annual
Technical Conference and Exhibition, Las Vegas, Nevada,
September 23-26, 1979.
3. Bonett, A. and Pafitis, D.: “Getting to the Root of Gas
Migration,” Oil Field Review, Vol. 8, No. 1, March 1,
1996, pp. 36-49.
4. Hartog, J.J., Davies, D.R. and Stewart, R.B.: “An
Integrated Approach for Successful Primary
Cementations,” SPE paper 9599, presented at the SPE
Middle East Technical Conference, Manama, Bahrain,
March 9-12, 1981.
5. Soran, T.U., Chukwu, G.A. and Hatzignatiou, D.G.: “Gas
Channeling and Micro-Fractures in Cemented Annulus,”
SPE paper 26068, presented at the SPE Western Regional
Meeting, Anchorage, Alaska, May 26-28, 1993.
6. Robert, B. and Art, T.: “Expansive and Shrinkage
Characteristics of Cement under Actual Well Conditions,”
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Journal of Petroleum Technology, Vol. 25, No. 8,
August 1973, pp. 905-909.
Symposium, San Francisco, California, June 29 - July 2,
2008.
7. Cooke Jr., C.E., Kluck, M.P. and Medrano, R.: “Field
Measurements of Annular Pressure and Temperature
during Primary Cementing,” Journal of Petroleum
Technology, Vol. 35, No. 8, August 1983, pp. 1,429-1,438.
17. Hibbeler, J.C., DiLullo, G. and Thay, M.: “Cost-Effective
Gas Control – A Case Study of Surfactant Cement,” SPE
paper 25323, presented at the SPE Asia Pacific Oil and
Gas Conference, Singapore, February 8-10, 1993.
8. Sabins, F.L., Tinsley, J.M. and Sutton, D.L.: “Transition
Time of Cement Slurries between the Fluid and Set State,”
Conference and Exhibition, Dallas, Texas, September 2124, 1980.
18. Santara, A., Reddy, B.R., Liang, F. and Fitzgerald, R.:
“Reaction of CO2 with Portland Cement at Downhole
Conditions and the Role of Pozzolanic Supplements,” SPE
paper 121103, presented at the SPE International
Symposium on Oil Field Chemistry, The Woodlands,
Texas, April 20-22, 2009.
9. Myrick, B.D.: “Field Evaluation of an Impermeable
Cement System for Controlling Gas Migration,” SPE paper
11983, presented at the SPE Annual Technical Conference
and Exhibition, San Francisco, California, October 5-8,
1983.
10. Jones, R.R. and Carpenter, R.B.: “New Latex, Expanding
Thixotropic Cement Systems Improve Job Performance
and Reduce Costs,” SPE paper 21010, presented at the
SPE International Symposium on Oil Field Chemistry,
Anaheim, California, February 20-22, 1991.
11. Dean, G.D. and Brennen, M.A.: “A Unique Laboratory
Gas Flow Model Reveals Insight to Predict Gas Migration
in Cement,” SPE paper 24049, presented at the SPE
Western Regional Meeting, Bakersfield, California, March
30 - April 1, 1992.
12. Ramirez, H.B., Santara, A., Martinez, C. and Ramos, X.:
“Water-Gas Migration Control and Mechanical
Properties Comparison with a Quick-Setting Slurry
Design (QSSD) to be Applied in a Production Cementing
Job for Ecuador,” SPE paper 123085, presented at the
SPE Latin American and Caribbean Petroleum
Engineering Conference, Cartagena, Colombia, May 31 June 3, 2009.
13. Farias, A.C., Suzart, W.P., Ribeiro, D., Santos, P.R. and
Santos, R.: “High Static Gel Strength Cement Slurries to
Hold Gas Migration-Laboratory Surveys,” paper
presented at the 7th Well Engineering Seminar in El
Salvador, October 16-18, 2007.
14. Calloni, G., Antona, P.D. and Moroni, N.: “A New
Rheological Approach Helps Formulation of Gas
Impermeable Cement Slurries,” Cement and Concrete
Research, Vol. 29, No. 4, April 1999, pp. 523-526.
15. Moran, L. and Savery, M.: “Fluid Measurements through
Eccentric Annuli: Unique Results Uncovered,” SPE paper
109563, presented at the SPE Annual Technical
Conference and Exhibition, Anaheim, California,
November 11-14, 2007.
16. Inverson B., Darbe, R. and McMechan, D.: “Evaluation
of Mechanical Properties of Cement,” ARMA paper 08293, presented at the 42nd U.S. Rock Mechanics
78
SPRING 2013
19. Santara, A., Reddy, B.R. and Antia, M.: “Designing
Cement Slurries for Preventing Formation Fluid Influx
after Placement,” SPE paper 106006, presented at the
SPE International Symposium on Oil Field Chemistry,
Houston, Texas, February 28 - March 2, 2007.
20. Moroni, N., Santara, A., Ravi, K. and Hunter, W.:
“Holistic Design of Cement Systems to Survive CO2
Environment,” SPE paper 124733, presented at the SPE
Annual Technical Conference and Exhibition, New
Orleans, Louisiana, October 4-7, 2009.
21. Osazuwa P., Mathias, A. and Herve, F.: “New
Centralizers Improve Horizontal Well Cementing by
100% Over Conventional Centralizers in the Niger Delta
Basin,” SPE paper 67197, presented at the SPE
Production and Operations Symposium, Oklahoma City,
Oklahoma, March 24-27, 2001.
62884araD10R1_ASC026 3/15/13 11:43 PM Page 12
BIOGRAPHIES
Abdulla F. Al-Dossary joined Saudi
Aramco in December 2005. He began
his career as a Workover Engineer
working with the Workover
Department. In April 2012, Abdulla
went to work with the Northern Area
Oil Drilling Department as a Drilling
Engineer.
He received his B.S. degree in Mechanical Engineering
(KFUPM), Dhahran, Saudi Arabia, in 2005. In 2011,
Abdulla received his M.S. degree in Petroleum Engineering,
also from KFUPM.
He has published and presented four Society of
Petroleum Engineers (SPE) papers.
Scott S. Jennings is the Group Leader
for cementing at Saudi Aramco’s
Exploration and Petroleum
Engineering Center – Advanced
Research Center (EXPEC ARC). He
has 32 years of experience in
cementing. Prior to joining Saudi
Aramco in 1987, Scott assumed duties that included
stimulation, cementing and sand control with Halliburton
Co. in East Texas and the Middle East Region. His areas of
interest are developing standards and test equipment, well
construction, gas migration prevention and long-term
cement durability. Scott is the Saudi Aramco voting
member of the American Petroleum Institute Subcommittee
10 and a long-term member of the Society of Petroleum
Engineers (SPE).
In 1980, he received a B.S. degree in Chemistry from
Angelo State University, San Angelo, TX.
SPRING 2013
79
62884araD11R1_ASC026 3/15/13 11:43 PM Page 1
80
62884araD11R1_ASC026 3/15/13 11:43 PM Page 2
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SPRING 2013
81
62884araD11R1_ASC026 3/15/13 11:43 PM Page 3
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, fax and phone numbers are
listed on page 81.
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Varies, but an average of 2,500-3,500 words, plus
illustrations/photos and captions. Maximum length should
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What to send
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submit UNIX files) via e-mail or on disc, plus one hard copy.
Send illustrations/photos and captions separately but
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information follows under Format).
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Use to thank those who helped make the article possible.
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in the text may be indicated with placeholders. Initial
submission may include copies of originals; however,
publication will require the originals. When possible, submit
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62884araD1R2_ASC027 3/17/13 3:46 PM Page 3
Additional Content Available Online at: www.saudiaramco.com/jot
H2S Early Notification System for Production Pipelines: A Pilot Test
George J. Hirezi, Faisal T. Al-Khelaiwi and Mohammed N. Al-Khamis
ABSTRACT
The produced fluid of an oil field located in the Eastern Province of Saudi Arabia contains relatively high levels of H 2S. A pilot
test was conducted by Saudi Aramco to install a wireless gas detection system along an oil pipeline in this field. The pilot test
objectives included:
• Determining the communication availability and reliability of the remote wireless sensors in areas where extending
hardwired and fiber optic networks proved impractical and expensive.
• Evaluating the usefulness of this system for early notification of toxic gas releases or pipe leaks in and around critical
geographical areas by alerting the console operator via email and Short Message Service (SMS).
Intelligent Field Infrastructure Adoption: Approach and Best Practices
Soloman Almadi and Tofig Al-Dhubaib
ABSTRACT
The drive to implement the latest optimal intelligent field infrastructure (IFI) is a continuous goal for oil and gas operators. This
requires the right balance between technology, business drivers and evolving implementation requirements. A successful
intelligent field implementation relies on a robust real-time field to desktop data acquisition and delivery system designed with
clearly defined data acquisition requirements. The data acquisition requirements definition should include data type, acquisition
frequency, resolution, integrity, quality and reliability.
Real-Time Estimation of Well Drainage Parameters
Mohammad S. Al-Kadem, Faisal T. Al-Khelaiwi and Meshal A. Al-Amri
ABSTRACT
The well drainage pressure and radius are key parameters of real-time well and reservoir performance optimization, well test
design and location identification for new wells. Currently, the primary method of estimating the well drainage radius is buildup
tests and a subsequent well test analysis. Such buildup tests are conducted using wireline run quartz gauges for an extended well
shut-in period, resulting in deferred production and risky operations.
Solar Power Integration Challenges: Intermittency and Voltage Regulation Issues
Mahmoud B. Zayan
ABSTRACT
Grid-connected solar energy generation is expected to multiply over the coming decades. Solar power generation brings many
benefits, such as reduced greenhouse gases and pollutant emissions, diversity of fuel supplies and displacement of costly fossil
fuel generation. Consequently, achieving higher penetration levels of solar energy in the market depends primarily on the
viability and reliability of the integrated system. A considerable barrier to the sustainability of solar power generation is the
constrained ability to control voltage as a result of weather related intermittency and the heavy reliance on inverters and other
power electronic devices to interface with the grid. To overcome those barriers, distribution networks will have to be designed
differently, and innovative smart grid technologies will have to be developed so as to optimize contributions from solar resources
while preserving the integrity of the grid.
62884araD1R2_ASC027 3/17/13 3:46 PM Page 4

adnan kanaan seif

Transcription

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