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ABSTRACT
This article describes a case study detailing
planning,completion, testing, and production of the first
MaximumReservoir Contact (MRC), Multilateral (ML) and
SmartCompletion (SC) deployment in Ghawar field.
The well was drilled and completed as a proof of concept.It was
completed as a trilateral and was equipped with a SCthat
encompasses a surface remotely controlled hydraulictubing,
retrievable advanced system coupled with a pressureand temperature
monitoring system.
The SC provides isolation and downhole control ofcommingled
production from the laterals. Using the variableposition flow
control valve, the well managed to improve andsustain oil
production by eliminating water production.Monitoring the rate and
the flowing pressure in real timeallowed optimal well
production.
The appraisal and acceptance loop of the completion hasbeen
closed by having this well completed, put on productionand tested.
Approval of the concept was achieved when theanticipated benefits
were realized by monitoring the actualperformance of the well.
Leveraged knowledge from this pilot has provided aninsight into
SC capabilities and implementation. Moreover, ithas set the stage
for other developments within Saudi Aramco.
BACKGROUND
Haradh forms the southwest part of the Ghawar oil fieldlocated
about 80 km onshore from the Arabian Gulf in theEastern Province of
Saudi Arabia, Fig. 1. The Haradh fieldconsists of three increments
where the initial productionstarted in May 1996 from Increment 1,
followed by Increment2 and 3 in April 2003, and January 2006,
respectively.
Increment 1 was initially developed using mainly verticalwells,
while Increment 2 was developed with horizontal wells.The
subsequent Maximum Reservoir Contact (MRC),Multilateral (ML) wells
and Smart Completion (SC)installations in Increment 2 were part of
a proof of conceptproject to test and evaluate the impact of these
technologies onreservoir, well performance and overall reservoir
managementstrategies. As a result of the proof of concept
project,Increment 3 was developed with MRC, ML wells with SCs.
Modeling was used extensively to illustrate the
potentialbenefits of the incremental expenditure of MRC, ML
wellswith SCs vs. conventional completions1, 2. Several
authorsquantified potential gains from using such wells
andcompletions in the fields development3, 4.
HRDH-A12 is the first MRC, ML well that was equippedwith SCs in
Ghawar field. It was drilled and completed as atrilateral selective
producer with a surface controlled, variable,multi-positional
hydraulic controlled system.
This article discusses a closed-loop approach that led
toefficient real time production optimization. The evaluationloop
of the technology was closed when the well wascompleted, put on
production and tested. Approval of theconcept was achieved when the
anticipated benefits wererealized by monitoring the actual
performance of the well.This article describes a case study
detailing planning,completion, testing and production. It concludes
with impactand lessons learned for future SCs.
SAUDI ARAMCO JOURNAL OF TECHNOLOGY SPRING 2009 63
Using Downhole Control Valves to Sustain OilProduction from the
First Maximum ReservoirContact, Multilateral and Smart Well
inGhawar Field: Case StudyAuthors: Saeed M. Mubarak, Tony R. Pham,
Sultan S. Al-Shamrani and Muhammad Shafiq
Fig. 1. Ghawar field map.
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64 SPRING 2009 SAUDI ARAMCO JOURNAL OF TECHNOLOGY
The SC, using three variable downhole flow control valves,was
designed to provide control of the inflow from each openhole
section of the well, Fig. 3. These valves operate asdownhole chokes
to restrict or completely shut off productionfrom any interval with
increasing water cut over time.
Nodal analysis and production simulation were conductedto design
and optimize choke sizes. In turn, this enabled theoptimum downhole
control setting during the production lifeof the well, Fig. 4.
The completion was designed to meet the following
keyobjectives5:
Individual zonal production control with a remotelycontrolled
hydraulic flow control valve.
Real time reservoir pressure and temperature data.
Zonal isolation between the three laterals.
Equipment was qualified for the production life of the well.A
Permanent Downhole Monitoring System (PDHMS) wasselected to be
placed above the top packer to monitor flowingand shut-in pressures
and temperatures. Flow control valvesare equipped with 11
positions, of which one is fully closedand one is equivalent to the
tubing flow area. The flow areasof the remaining nine positions
were individually designed torepresent the most optimum choke
settings for the life of the
GENERAL GEOLOGY
The producing horizon at the well location belongs to the
lowermember of the Arab-D formation, which is characterized by
acomplex sequence of anhydrite and limestone events withvarying
degrees of dolomitization. This particular well islocated in the
west flank of Haradh Increment 2, in an areacharacterized by
heterogeneity in reservoir rock properties,salinity and fluid
movement. Fluid mechanism in this specificarea is highly influenced
by the presence of fracture corridorsand strataform super
permeability. The motherbore of this well(L0) extends to the
vicinity of the projected flood front whilethe other laterals
extend away from the flood front, Fig. 2.
The location dictated drilling a well that can capture realtime
data, maximize control, optimize production, andincrease well
value.
COMPLETION STRATEGY
After analyzing the reservoir data, SC solutions were soughtto
meet reservoir and production main objectives, includingbut not
limited to:
Sustain well productivity.
Improve sweep.
Provide selective control of multiple laterals.
Manage water production.
Minimize production interruptions.
COMPLETION DESIGN
The HRDH-A12 well was drilled in 2004, and was completedwith a 7
liner set horizontally into the Arab-D producinginterval. A 618
horizontal open hole was then drilled out fromthe bottom of the 7
liner. Due to heavy losses while drillingL0, a 4 liner was set
covering part of this open hole section.Two 618 horizontal
sidetracks (L1 and L2) were then drilledfrom the 7 liner completing
the trilateral well. The well wasinitially completed and put on
production from barefootlaterals. A year later, the well was worked
over to install a SC.
Fig. 2. HRDH-A12 location.
Fig. 3. HRDH-A12 SC schematic.
Fig. 4. Downhole choke valve flow area and recommended flow
rate.
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Table 1. Lateral lengths
well. The flow control device was successfully qualified
with1,320 individual cycles, and multiport packers were used
forthis installation, Fig. 5.
DRILLING AND GEOSTEERING
The well was drilled across the top 10 ft of the Arab-D with
a
total reservoir contact of 5.6 km, Table 1, and average
porosity
of 18% which was accomplished through real-time geosteering.
During the drilling phase, the plan was revised regularlybased
on actual zone depths. Due to sudden changes information dip, a few
deviations from the plan occurred.Among the changes was the placing
of the motherbore and L1lower in the reservoir. Lateral 2, however,
climbed to tightanhydrite above the Arab-D and was steered back
into goodporosity by having a sidetrack. During drilling, total
loss ofreturns was encountered in all three laterals.
The design of this trilateral honored the objective thatcalls
for having the proper separation between laterals toavoid
interference6.
COMPLETION PERFORMANCE
A multidisciplinary team consisting of reservoir,
drilling,completion and production engineers, as well as the
vendorsexperts, was formed to assure smooth and
successfuloperation. The team applied a project management
approachto the design, planning and installation process.
The SC was subsequently installed in early April 2005.During the
equipment testing, installation and subsequentflow testing of the
well, each of the valves were actuatedthrough more than 10 complete
cycles (110 position changes),which is equivalent to several years
of typical operation. As aprecautionary measure and to ensure the
functionality of theDownhole Control Valves, the valves were tested
downholeprior to setting the packers.
During testing of the well once the completion was installed,a
multiphase flow meter provided three-phase flow ratemeasurements.
This data along with the downhole pressureand temperature
measurements were transmitted in real timefor instantaneous
analysis and subsequent decision making.
WELL PERFORMANCE
Prior to the installation of the SC, the well was put
onproduction from barefoot laterals. The well was tested at arate
of 18,000 barrels per day (MBD) dry oil at a chokesetting of 95/64.
The analysis of the transient test that wasconducted in June 2004
indicated a productivity index (PI) of350 BPD/psi as compared to 17
or 31 BPD/psi for offsetvertical or horizontal wells. The well test
indicated thepresence of anisotropy, which is in good agreement
with theimage log results and loss of returns while drilling,
whichindicates the presence of fractures/faults intersecting
thehorizontal well.
Within two months of production, the well startedproducing
water. The last test prior to the workover indicateda water cut of
about 23% at an oil rate of 8 MBD.
Laterals Pressure Transit Testing
During the testing of the well post SC installation,
shortduration buildups were performed on each lateral.
Theproductivity testing for each of the laterals wasaccomplished by
testing an individual lateral while the othertwo laterals were
closed. Buildup tests were conductedfollowing the production rate
tests by shutting-in the wellusing surface valves.
This was done to determine the PI of each lateral, whichhelped
to decide which downhole choke setting to use for eachlateral when
the production is commingled. Details of theinitial productivities
of the laterals are shown in Table 2.
If it were not for the SC and PDHMS capabilities,conducting
individual lateral transient tests in amultilateral well would not
be feasible and would requireintensive intervention.
SAUDI ARAMCO JOURNAL OF TECHNOLOGY SPRING 2009 65
Fig. 5. Gauge, multiport packer and flow control valve.
Lateral LengthL0 7.125 ftL1 4,042 ftL2 7,200 ft
Total 18,367 ft
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66 SPRING 2009 SAUDI ARAMCO JOURNAL OF TECHNOLOGY
to have L0 closed, L1 opened at a choke setting of 3 and
L2opened at a choke setting of 2, Fig. 6. Using the surfacechoke,
the total withdrawal of the well was restricted to an oilrate of 5
MBD and 0% water cut. Since then, the well hasbeen producing at
this rate with no water production.
Optimization of the SC downhole chokes settings resultedin a
significant improvement in well performance. Nodalanalysis was
conducted to optimize the downhole chokesettings. Production
optimization tools can be used as a steptoward intelligent and
integrated application of SCs3.
CONCLUSIONS
Leveraged knowledge from this experiment provided insightinto SC
capabilities and implementation; moreover, it set thestage for
other increment developments (i.e., HaradhIncrement 3). Several
lessons learned of high impact can beidentified, most notably:
1. Quality control of the system is a priority for
successfulimplementation. This can be illustrated by function
testingthe completion in hole prior to setting the packers.
2. HRDH-A12 could have been dead without SC.
3. Real time surveillance and control capabilities
permitproactive measures.
4. Downhole flow control can alleviate the natural
fracturesimpact on dominating production.
5. Smart Completions have demonstrated the potential toreduce
well interventions7.
ACKNOWLEDGEMENTS
The authors would like to thank Saudi Aramco managementfor
permission to publish this article.
REFERENCES
1. Afaleg, N., Pham, T., Otaibi, U., Amos, S. and Sarda,
S.:Design and Deployment of Maximum Reservoir ContactWells with
Smart Completions in the Development of a
Optimization of Downhole Choke Settings
The well started producing water after two months ofproduction.
After five months of production at an average oilrate of 8 MBD, the
water cut had increased to 30%.
Upon that finding, a comprehensive rate test was done onthe
well. The testing involved several downhole choke
settingscombinations with an objective to come up with
optimizedsettings that honor the production strategy for the well
andthe area, Table 3.
Test results indicated that L0 was completely wet while
theproduction rate and water cut from L1 were choke sensitive,which
is a possible indication of the existence of coningthrough vertical
fractures. The impact of natural fractures ondominating production
in L1 was controlled by using thedownhole flow control technology.
For instance, when thelateral operated at higher drawdown (i.e.,
higher downholechoke setting), the water cut increased as water
elevated viavertical fractures, Fig. 6. The final configuration was
adjusted
Table 2. Buildup test results
Transient Test ResultsLateral Productivity Index (PI)
(BPD/psi)L2 165L1 60L0 80
Table 3. Rate test results at variable downhole choke
settings
Test Downhole Choke Setting Rate WC%
L0 L1 L2
1 5 3 2 7.7 222 5 0 0 1.0 973 0 0 5 3.5 654 0 0 2 3.5 05 0 3 0
3.9 06 10 10 10 Dead 7 0 3 2 6.0 0
Fig. 6. Higher drawdown triggers water production through
vertical fractures.
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Carbonate Reservoir, SPE paper 93138, presented at theSPE Asia
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SAUDI ARAMCO JOURNAL OF TECHNOLOGY SPRING 2009 67
BIOGRAPHIES
Saeed M. Al-Mubarak is a Supervisorin the Southern Area
ReservoirManagement Department, and aspecialist in Real-Time
ReservoirManagement (RTRM) and IntelligentFields. He has been very
involved inthe development, the design and the
implementation of Intelligent Fields and various advancedwell
completion systems. Saeed has more than 15 years ofpetroleum
industry experience. His contributions to theinternational
technical community are numerous, includinghis acceptance to be a
Society of Petroleum Engineers (SPE)Distinguished Lecturer in RTRM
during 2009-2010. Saeedreceived his B.S. degree in Chemical
Engineering in 1992from King Fahd University of Petroleum and
Minerals(KFUPM), Dhahran, Saudi Arabia and is currentlypursuing a
M.S. degree in Petroleum Engineering from thesame university.
Tony R. Pham is a Senior PetroleumEngineering consultant with
more than20 years of experience in the petroleumindustry. In 1976
he graduated with aB.S. degree in Petroleum Engineeringfrom the
Texas A&M University,College Station, TX.
Sultan S. Al-Shamrani is a ReservoirEngineer working in the
SouthernArea Reservoir ManagementDepartment. He has 5 years
ofindustry experience, mainly in newfield development and
intelligent fieldimplementation. Sultan graduated
from the University of Tulsa, Tulsa, OK in 2004 with aB.S.
degree in Petroleum Engineering.
Muhammad Shafiq is a Senior AdvanceCompletions Architect with
Schlumbergerin Saudi Arabia. He is currentlyresponsible for
real-time reservoirmonitoring and control. Muhammad has12 years of
oil field experience. Hereceived his B.S. degree in Petroleum
Engineering from the University of Engineering and
Technology,Lahore, Pakistan in 1995.