HARADH-III: Industry's Largest Field Development Using Maximum ...

Abdulaziz O. Al-Kaabi
Dr. Nabeel Al-Afaleg
Tony Pham
Ali S. Al-Muallem
Fahad A. Al-Bani
Richard G. Hart
Drew Hembling
HARADH-III: Industry’s Largest
Field Development Using
Maximum Reservoir Contact
Wells, Smart Well Completions
and I-Field Concept
Abdulaziz O. Al-Kaabi is a Petroleum Engineering
Consultant with Saudi Aramco Reservoir Management
Department. He received his B.S. and M.S. from King Fahd
University of Petroleum & Minerals (KFUPM) and a Ph.D.
from Texas A&M University, all in Petroleum Engineering.
Abdulaziz’s experience spans more than 20 years of
teaching, research and industry involvements. Prior to
joining Saudi Aramco in 2002, Dr. Al-Kaabi served as the
Director of the Center for Petroleum & Minerals and as
Associate Professor of Petroleum Engineering at the
Petroleum Engineering Department of KFUPM.
Dr. Nabeel Al-Afaleg is currently Chief Technologist for
the Reservoir Engineering Technology Team within Saudi
Aramco. He has 20 years of experience with Saudi Aramco
during which he was involved in various assignments and
projects focused on field development and reservoir
management and was Haradh Inc-III development Team
Leader. He has numerous publications in these areas.
Nabeel has been a member in the international SPE since
1984. He graduated from the University of Southern
California in 1996 with an M.S. and Ph.D. in Petroleum
Engineering. He also holds a B.S. in Petroleum Engineering
from King Fahd University.
Tony Pham is a Petroleum Consultant with the Abqaiq
Reservoir Management Division. He has a B.S. in Petroleum
Engineering from Texas A&M University. Tony joined Saudi
Aramco in 1982 and is currently involved in drilling operations
and planning for the Khurais Complex Development.
Ali S. Al-Muallem is a General Supervisor with the
Saudi Aramco Reservoir Management Department. He

eceived his B.S. in Petroleum Engineering from King Fahd
University of Petroleum & Minerals (KFUPM). His
experience includes 19 years with Saudi Aramco, where he
worked in several departments including Production
Engineering, Reservoir Simulation and Reservoir
Management. Ali is currently responsible for the reservoir
management of the giant Ghawar field and was directly
involved with the latest two increment developments in the
Haradh area.
Fahad A. Al-Bani is a Supervisor in the Drilling
Engineering Department, Development Drilling Engineering
Division. Fahad graduated with a B.S. in Petroleum
Engineering from King Saud University and joined Saudi
Aramco in 1996 as Drilling Engineer. He has been a
member of SPE since 1998.
Richard G. Hart is an Operations/Field Geologist for the
Southern Fields Characterization Division currently
assigned to the Khurais Complex Development Team. He
received his B.S. in Geoscience from Purdue University and
a M.A. in Geology from the University of Missouri. Rick
worked as a Development Geologist for Marathon Oil
Company for 22 years and joined Saudi Aramco in 2001.
Drew Hembling is a Completion Team Leader working
in the Petroleum Engineering Support Division of Saudi
Aramco’s Producing Facilities Development Department.
He graduated from West Virginia University with a B.S. in
Petroleum Engineering in 1983. Drew worked for Conoco
Inc. from 1983 to 1997, and ARCO in Anchorage from
1997 to 2000. He joined Saudi Aramco in 2000 as a
Completion Specialist.
ABSTRACT
The development of Haradh-III in the southernmost area of
Ghawar represents a major shift in paradigm in terms of the
combination of the technologies. The field development
combines four main technology features which include
maximum reservoir contact (MRC) wells, smart
completions, extensive use of real-time geosteering and I-
Field initiatives.
This paper describes the motivation, implementation, and
post-production evaluation of this unique field
development. In the case of Haradh-III, field development
with smart MRC wells delays water encroachment,
improves flood front conformance and recovery, lowers
water production and long term development and operating
costs. Bottom water encroachment into the wellbore is
mitigated as downhole Internal Control Valves (ICV), as
part of the smart completion, are adjusted. This in turn
lengthens the life of the well, allows sweep and recovery to
take place in the reservoir below the horizontal wellbores
48 SAUDI ARAMCO JOURNAL OF TECHNOLOGY SUMMER 2007
through the most effective sweep process: the replacement
mechanism by gravity. The objectives of the development
are accomplished utilizing a reduced number of wells,
minimizing the accompanying infrastructure, therefore
lowering the capital expenditure while reducing the
operating cost by maintaining, on a long-term basis, a lowwater
producing system, all occurring in real time and
within the I-Field environment.
INTRODUCTION
Production from Haradh-III development started in
February 2006. The project included a combination of
MRC wells, smart completions, geosteering, and I-Field
concept which provides real time access to downhole
information. The efficient integration along with
understanding of the fluid flow mechanisms in the reservoir
was the key to the success of the project.
Haradh field locates at the southernmost portion of the
Ghawar complex and covers an area 75 km long and is 26
km at its widest section (Fig. 1). The field consists of three
sub-segments of approximately equivalent reserves, with an
aggregate Oil Initially In Place in the order of tens of
billions of barrels. Initial production from Haradh-I started
in May 1996, followed by Haradh-II and Haradh-III in
April 2003 and February 2006, respectively. The field
developments, occurring over a span of a decade, offer a
unique opportunity in gauging the impact of technologies.
Haradh-I was developed exclusively by utilizing vertical
wells, whereas horizontal completions provided the primary
configuration for producers/injectors in Haradh-II. Haradh-
III, the main focus of this paper, was developed by relying
mainly on smart MRC completions (Fig. 2) within an I-
Fig. 1. 3D map showing Haradh field and its three main subdivisions.
Schematic (right) shows Ghawar complex.

Fig. 2. Schematic map showing Haradh-III initial development plan utilizing
MRC wells 1 .
Field framework. The total Haradh production capacity is
900 MBD, with equal contributions from the three
respective sub-segments I, II and III with key statistics for
Haradh-III as shown in Table-1 1 .
GEOLOGICAL SETTING
Geologically, the Arab-D carbonate reservoir is divided into
several zones: Zone-1, at the top, is a thin layer separated
from the main producing zones by an impermeable
nonporous layer of anhydrite. Zone-2A, below Zone-1, is
mostly skeletal oolitic limestone with scattered vugs and
local super-permeability zones (Super-K). Below Zone-2A is
Production,
MBD
300 MPFM 40
Injection, MBD 560 RTU/SCADA 72
Producers 32 Flowlines (10”) 68 Km
Injectors 28 On-stream Date 2/06
EV/OBS 12 Injection Startup 9/05
PDHMS 40 ICV’s 87
Average PI 150
Average Reservoir
Contact
5 Km
MRC Wells: Combination of Tri-laterals and Quad-Laterals
Legend:
MFPM Multiphase Flow Meter
RTU Remote Testing Unit
ICV Internal Control Valve (Sub-Surface)
PDHMS Permanent Down-hole Monitoring System
EV/OBS Evaluation/Observation Wells
Table 1. Installation Timing Breakdown
Fig. 3. Borehole Image logs showing Super-K interval (left) and vertical
fractures (right). The middle photograph is an analog from Arab-D outcrop
showing vertical fractures intersecting a leached stratiform (Super-K) interval.
Zone-2B, which commonly includes dolomite and
cladocoropsis based Super-K intervals 2 (Fig. 3). Below
Zone-2B are Zones-3A and -3B which have significantly
lower reservoir quality.
Major and minor faults identified from 3D seismic data
and associated fracture swarms (corridors) have been
observed in various degrees throughout the Arab-D
reservoir in adjacent areas 3 . In addition, diffuse fractures
are pervasively observed in cores (Fig. 4). More details on
reservoir characterization are presented next.
Fracture and Super-K Characterization
The fracture network in the Haradh Arab-D reservoir
mainly corresponds to fracture swarms. At wellbore scale,
fracture swarms are observed as moderately dipping
fractures with scattered orientations with the majority of
the orientations parallel to the maximum stress direction. At
reservoir scale, fracture swarms form a series of fracture
corridors that serve as conduits to bring water in-field. This
conclusion is in agreement with the observations from
Arab-D outcrops in central Saudi Arabia (Fig. 3). It is also
supported by dynamic data from well performance.
The stratiform Super-K 4 on the other hand has been
observed as a super-permeability layer with high flow. The
Fig. 4. Photograph of Arab-D core sample showing diffuse fractures.
SAUDI ARAMCO JOURNAL OF TECHNOLOGY SUMMER 2007 49

Fig. 5. Ranking analysis of key reservoir parameters 5 .
prevalence of super-permeability, however, points to a corallike
organism, referred to as cladocoropsis 2, 5 , which was
dolomitized and subsequently leached out leaving pencil-sized
vugs yielding horizontal permeabilities in the Darcy Range.
The fractures and the Super-K, when interconnected on a
field-wide basis, contribute significantly to water
encroachment which tends to reduce productivity of
individual wells. The understanding of how fluids flow in
the reservoir is dominantly affected by these two important
geological features. Defining their effects is vital before any
field development scheme can be formulated and accepted.
This is the subject of the next section.
Understanding Fluid Flow Mechanics in Haradh Field
The prerequisite for an optimum field development starts
with the understanding of fluid flow mechanisms in the
reservoir. As the main path of fluid flow is controlled by the
high permeability (i.e., stratiform Super-K and fractures) it
is important to define and quantify their impact. Using
performance of the relatively more mature neighboring area
(Haradh-I) to evaluate the reservoir behavior, different
models (probabilistic models, streamline models and dual
porosity-permeability models) were constructed for this
purpose. Results from such models were then compared
against field observations for validation before final
conclusions were drawn.
PROBABILSTIC MODELS
The identification of Super-K and fractures involves
uncertainty. Thus their impact on cumulative production
and recovery has to be formulated probabilistically.
Tested probabilistic models used random population for
seven different key reservoir parameters including fractures
and Super-K in an experimental design modeling
procedure 3, 6 . Probability analyses ranked reservoir
50 SAUDI ARAMCO JOURNAL OF TECHNOLOGY SUMMER 2007
parameters according to their impact on production and
recovery. Seven parameters were identified in the study.
These include: (1) The connectivity of the fracture network
(Lcon), (2) The aquifer size (Vaq), (3) Super-K
permeabilities (Ksk), (4) Skin factor (Skin), (5) Vertical-tohorizontal
permeability ratio (KZH), (6) Fracture
conductivity of two fracture sets (C1, C2), and (7) Residual
oil saturation (Sorw). Various combinations of parameters
were also studied (e.g., the combination of fracture and
Super-K permeabilities).
The Tornado Chart of Fig. 5 indicates that the three most
controlling parameters (in decreasing order) are: (1) The
connectivity of the fracture network (Lcon), (2) The aquifer
volume (Vaq), and (3) Super-K permeabilities (Ksk).
Based on the above conclusions, we constructed some
phenomenological models to better define the fluid flow
mechanisms in the reservoir.
PHENOMENOLOGICAL MODELS
Two phenomenological models (fine-grid 3D simulation,
and streamline) were constructed in the neighboring
Haradh-I to evaluate which one of the two heterogeneities
(i.e., stratiform Super-K or fractures) is mainly responsible
for the observed early water encroachment.
Several observations were concluded from the fine grid
3D model. It was found that the Super-K layer needs to be
continuous from the injector to the producer to control
early water breakthrough. This implies that the Super-K
layer has to be correlated and interconnected over a vast
(several kilometers) distance. This is not substantiated with
field observation.
The second phenomenological model is the streamline
model. The objective of such a model is to study the role of
fractures in fluid flow and to identify the “responsible
fractures” from all of the faults/fracture lineaments identified
from 3D seismic data. In this case, “responsible fractures”
refer to fractures that are responsible for premature water
breakthrough in the producing area of the reservoir.
For simplicity, the streamline model was set up with
constant pressure boundaries for both producers and
injectors. Aggregated fracture swarms (corridors) tend to
provide better pressure support than those that are in low
fracture density area. The main reason is that fractures tend
to be more interconnected when their density of occurrence
is high. It was observed that water tends to spill
horizontally and outwardly into the matrix as soon as it
reaches the end of the connected fracture network.
Another observation is that conductive fractures
generally oriented in the window of N70E direction and
EW direction. The N70E direction corresponds to the
regional stress field in the Arabian Peninsula while the EW

Fig. 6. Water cut vs. time showing the impact of downhole choke optimization
– Well A-12.
direction corresponds to the localized phenomenon of the
Wadi Sahbah direction 7 .
The streamline model shows that not all fractures are
contributing to water breakthrough in Haradh-I with the
exception of fractures orienting in the N70E and EW
directions. Also, water tends to spill horizontally and
outwardly into the matrix; especially toward the end of the
fractures.
Since the streamline model is time-of-flight based, it is
important to validate the observation with a finite
difference model. For this purpose we constructed a dual
porosity dual permeability (DPDP) sector model which is
summarized next.
DUAL POROSITY DUAL PERMEABILITY
(DPDP) MODEL
Sector DPDP models were constructed to study the
displacement mechanism within the matrix and the
fractures. In the models, fractures and Super-K bodies were
represented by one medium (fracture medium) while matrix
and diffuse fractures were represented by the matrix
medium. Diffuse fractures in the matix medium acted as
vertical permeability enhancers. Complete discussion on the
simulation approach can be found in Ref. 11.
The results from the DPDP models validated the
observation from the streamline model. Where applicable,
water would move quickly in-field through fractures
network and spill out into the matrix. Also, the DPDP
model indicated a water displacement mechanism that is
bottoms-up. The placements of MRC laterals and the
installations of smart completions were field tested to take
advantage of this flow mechanism.
FIELD PILOT
Well A-12
Trilateral MRC well A-12 was drilled through the top of
Zone-2A and completed with hydraulically activated smart
downhole ICV in a high risk (fracture swarms) area. This
was done for the purpose of testing how the downhole ICV
could help optimize the production from various laterals
with respect to water management and oil productivity.
Loss of circulation was encountered in all three laterals.
From the experience in this particular area, loss of
circulation mostly indicates the presence of fractures. Due
to the proximity of the well to the flood front, the well cut
water about two months after it was put on production.
High water production was expected from the well as water
would cone through the fracture into the laterals.
During the tests, rates, water cuts, wellhead samples,
surface and downhole pressure values were collected for
different sets of combinations of downhole valves settings.
It was concluded that water production is choke sensitive
and can be optimized by adjusting downhole ICV. It was
observed that when the motherbore lateral was open at
choke setting 5 (10 is wide open and zero is fully closed),
the well loaded up with water and died. The lower lateral
by itself produced dry oil while the upper lateral is chokesensitive.
At the choke setting of 2, the upper lateral is dry;
on the other hand, the upper lateral produced 65% of
water when it was set at a choke setting of 5.
The well became dead when all downhole chokes were
set at a wide open position while the last test showed that
the well flowed at negligible water cut for more than 10
months at a low setting combination of the three laterals
(Fig. 6).
COST BENEFIT OF SMART MRC WELLS
Smart completions are necessary to ensure production
sustainability in the face of premature water encroachment
through fault/fracture systems. In fact, the well requirements
and relative unit costs would have been considerably higher
had vertical or conventional single-horizontal wells been
selected in lieu of MRC’s for Haradh-III. The development
of Haradh-III with smart MRC wells, over the long-term,
exhibits a much lower unit development cost 1, 8 in terms of
$/BPD, compared to vertical or horizontal wells without
smart completion (Fig. 7).
Implementation of smart wells will result in controlling
the water production and minimizing its negative impact on
oil productivity. Laterals that are cutting water are either
choked down or shut-off while the dry laterals maintain
production. Smart wells reduce dependence on workovers
since laterals shutdown or restriction is done from the
surface or remotely. Other associated operating costs such
as water treatment and disposal are also reduced as a
consequence of less water production.
SAUDI ARAMCO JOURNAL OF TECHNOLOGY SUMMER 2007 51

Relative Unit Cost (Dimensionless)
1.0
Fig. 7. Relative unit well costs for HRDH-III show impact of technologies.
Note: costs are relative to vertical wells in $/BPD 1 .
GEOSTEERING
The role of geosteering as an enabling technology has also
been previously noted 1, 9 . Combined with better than
predicted reservoir quality, its value was even more
pronounced in Haradh-III because accurate placement of
multilaterals within the Arab-D reservoir and the integrity
of borehole trajectories were necessary to achieve desired
target rates of 10 MBD. Decision processes and
coordination protocols between geologists, directional
drilling engineers and reservoir engineers were carefully
implemented to minimize well path tortuosity which could
cause potential production problems (e.g., water slumps in
the wellbore during wet production). Post-drilling
production tests yielded well PIs averaging 150 bbl/day/psi
– exceeding the planned PI of 100 bbl/day/psi.
I-FIELD AND STRATEGIC SURVEILLANCE
MASTERPLAN
0.7
I-Field was part of the Haradh-III strategic surveillance
masterplan – a prerequisite for the company’s reservoir
management tenets 1, 10 .
All 12 of the observation and 28 of the MRC
completions were equipped with downhole PDHMS
systems. All producers were equipped with multiphase
meters for real-time measurement of fluid rates. Data
(downhole pressure, temperature, and surface fluid rates)
was transmitted in real time to the headquarter offices for
monitoring and data analysis.
Field example on the value of real-time data is discussed
in a separate paper 1 .
POST-PRODUCTION PERFORMANCE
Haradh-III has been meeting production requirements of
300 MBD for more than six months. The well’s
performance and reservoir pressure behavior have been well
within or exceeded the planned criteria. Recent well testing
52 SAUDI ARAMCO JOURNAL OF TECHNOLOGY SUMMER 2007
0.35
VERTICAL HORIZONTAL MRC/SMART
and optimization of production from each laterals
confirmed the high well productivity of theMRC wells.
Water cut from the field has been less that 0.5% of total
production which could be even reduced by applying more
downhole choke optimization on selective individual
laterals.
CONCLUDING REMARKS
Haradh-III involved a unique field development process,
due to the convergence and successful integration of four
technologies: MRC well design, smart completions,
geosteering and I-Field. The project’s success can be
attributed to the understanding of the underlying fluid flow
mechanisms and the game-changing attributes of the four
aforementioned technologies and their successful integration
into the field development plan. The latter was made
possible by new processes which enabled rapid decisionmaking
in a collaborative multidisciplinary work
environment 1 .
ACKNOWLEDGEMENT
The authors would like to thank Nansen G. Saleri for his
leadership and pioneering views on Reservoir Management.
We also acknowledge the contributions of many individuals
from Saudi Aramco’s E&P community, as well as project
management teams.
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SAUDI ARAMCO JOURNAL OF TECHNOLOGY SUMMER 2007 53