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.

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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.

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.

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.

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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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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.

Carbonate Reservoir, SPE paper 93138, presented at theSPE Asia Pacific Oil and Gas Conference and Exhibition,Jakarta, Indonesia, April 5-7, 2005.

2. Mubarak, S., Afaleg, N.I., Pham, T.R., Zeybek, M. andSoleimani, A.: Integrated Advanced Production Loggingand Near Wellbore Modeling in a Maximum ReservoirContact (MRC) Well, SPE paper 105700, presented at the15th SPE Middle East Oil & Gas Show and Conference,Kingdom of Bahrain, March 11-14, 2007.

3. Yeten, B., Durlofsky, L.J. and Aziz, K.: Optimization ofSmart Well Control, SPE paper 79031, presented at theSPE International Thermal Operations and Heavy OilSymposium and International Horizontal Well TechnologyConference, Calgary, Alberta, Canada, November 4-7,2002.

4. Saleri, N.G., Kaabi, A.O. and Muallem, A.S.:Management Haradh III: A Milestone for Smart Fields,Journal of Petroleum Technology, November 2006,pp. 28-33.

5. Rundgren, G., Hydro, N., Algeroy, J., Hestenes, L.E.,Jokela, T. and Raw, I.: Installation of AdvancedCompletions in the Oseberg 30/9-B-38 B Well, SPE paper71677, presented at the 2001 SPE Annual TechnicalConference and Exhibition held in New Orleans,Louisiana, September 30 - October 3, 2001.

6. Nughaimish, F.N., Faraj, O.A., Al-Afaleg, N. and Al-Otaibi, U.: First Lateral Flow-Controlled MaximumReservoir Contact (MRC) Well in Saudi Arabia: Drillingand Completion: Challenges and Achievements: CaseStudy, SPE paper 87959, presented at IADC/SPE AsiaPacific Drilling Technology Conference and Exhibition,Kuala Lumpur, Malaysia, September 13-15, 2004.

7. Payne, J., et al.: Controlling Water Production UsingIntelligent Completion Technology in Multilaterals, SaihRaw Field, Oman, presented at the 2003 Oil and GasJournal High Tech Well Conference, Galveston, Texas,February 11-13, 2003.

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.