Jot Fall 2009

Fall 2009

THE SAUDI ARAMCO JOURNAL OF TECHNOLOGYA quarterly publication of the Saudi Arabian Oil Company

Lessons Learned from 100 Intelligent WellsEquipped with Multiple Downhole Valvessee page 2

Nonconventional Catalytic Process forUltimate Removal of Organic Sulfur-Containing Compounds in HydrocarbonFractionssee page 30

Journal of TechnologySaudi Aramco

On the Cover

A representation of a Smart Trilateral Maximum Reservoir

Contact Well where surface controlled downhole Inflow Control

Valves (ICVs) are used to manage the flow from each lateral.

These controllable valves, along with real time pressure

measurements, provide a means to optimize production, and

provide zonal isolation and flow control of commingled

production from different laterals or segments. Using the variable

positions of these valves, production can be managed in real time

to improve wells and reservoir performance.

This evolution of intelligent/smart wells over time reflectsthe different completion types where smart completions weredeployed. The first implementation of these completions inSaudi Aramco took place in conjunction with multilateralMRC wells in early 2004. Those implementations havedemonstrated their advantages over conventional completions;furthermore, they have opened up numerous improvementopportunities. Their deployment has not been limited to newwells; it has been extended to enhance performance of existingweak and dead conventional wells after converting them toMRCs and multilaterals.

2004 2005 2006 2007 2008

Birthof Smart(7” Liner)

Smart(ML/Expandable)

Smart(ML/Open Hole)

(ML/MPFM)

Smart(SL/Open Hole)(ML/Slim Hole)(SL/Slim Hole)

EVOLUTION OF INTELLIGENT WELLS WITH ICVS

The Saudi Aramco Journal of Technology ispublished quarterly by the Saudi Arabian OilCompany, Dhahran, Saudi Arabia, to providethe company’s scientific and engineeringcommunities a forum for the exchange ofideas through the presentation of technicalinformation aimed at advancing knowledgein the hydrocarbon industry.

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EDITORIAL ADVISORS (CONTINUED)

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CONTRIBUTIONS

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EDITOR

William E. BradshawThe Saudi Aramco Journal of TechnologyRoom 2014 East Administration BuildingDhahran 31311, Saudi ArabiaTel: +966/3-873-5803E-mail: [email protected]

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Khalid A. Al-FalihPresident & CEO, Saudi Aramco

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Fall 2009

THE SAUDI ARAMCO JOURNAL OF TECHNOLOGYA quarterly publication of the Saudi Arabian Oil CompanyJournal of Technology

Saudi Aramco

Contents

Lessons Learned from 100 Intelligent Wells Equipped with Multiple Downhole Valves 2Saeed M. Al-Mubarak, Naseem J. Al-Dawood and Salam P. Salamy

Drill Cuttings Re-Injection (CRI) Assessment for the Manifa Field: An Environmentally Safe and Cost-Effective Drilling Waste Management Strategy 9Yousef M. Al-Shobaili, Kirk M. Bartko, Philip E. Gagnard, Mickey Warlick and Ahmad Shah Baim

Thermodynamic Analysis of Formation of Black Powder in Sales Gas Pipelines 17Dr. Abdelmounam M. Sherik and Dr. Boyd R. Davis

Successful Utilization of Fiber Optic Telemetry Enabled Coiled Tubing for Water Shut-off on a Horizontal Oil Well in Ghawar Field 24Ahmed K. Al-Zain, Jorge E. Duarte, Surajit Haldar, Saad M. Driweesh,Ahmed A. Al-Jandal, Faleh M. Al-Shammeri, Vsevolod Bugrov andTashfeen Sarfraz

Nonconventional Catalytic Process for Ultimate Removal of Organic Sulfur-Containing Compounds in Hydrocarbon Fractions 30Dr. Farhan M. Al-Shahrani, Dr. Tiacun Xiao, Dr. Abdennour Bourane,Dr. Omer R. Koseoglu and Prof. Malcolm L.H. Green

Innovative Solution for Drilling Pre-Khuff Formations in Saudi Arabia Utilizing Turbodrill and Impregnated Bits 37Gabriel D. Carrillo, Usman Farid, Michael Albrecht, Perry Cook,Nouman Feroze and Kenneth Nevlud

Evaluation of Wellbore Stability during Drilling and Production of Open Hole Horizontal Wells in a Carbonate Field 44Dr. Hazim H. Abass, Mickey Warlick, Cesar H. Pardo, Mirajuddin R.Khan, Dr. Ashraf M. Al-Tahini, Dr. Dhafer A. Al-Shehri, Dr. HameedH. Al-Badairy, Yousef M. Al-Shobaili, Dr. Thomas Finkbeiner andSatya Perumalla

The Use of Multistage New Technology to Complete and Stimulate Horizontal Wells: Field Case 56Hassan M. Al-Hussain, J. Ricardo Solares, Hamad M. Al-Marri and Carlos A. Franco

Revitalization of Old Asset Oil Fields into I-Fields 63Dr. Mohammed N. Al-Khamis, Konstantinos I. Zormpalas, Hassan M. Al-Matouq and Saleh M. Al-Mahamed

2 FALL 2009 SAUDI ARAMCO JOURNAL OF TECHNOLOGY

ABSTRACT

The last decade has been marked by the emergence ofintelligent field (I-Field) technologies. Many E&P companieshave moved from the piloting and trial-testing mode towardstrategic implementation, demonstrating that these tech -nologies have shown their capabilities. While the currentdeployment of these technologies represents only a smallfraction of the overall installation, the trend is indicative ofthe shifting of attitudes and preferences within companies.Among those companies, Saudi Aramco has deployed fit-for-purpose technologies, such as intelligent wells equipped withmultiple downhole valves, as part of its best-in-class practices,Fig. 1. Continuous assessment of these technologies isimportant to provide reassurance on their values.

The resulting performance of this technology is a functionof multiple factors, from reservoir parameters and completionschemes to surface infrastructure. Understanding and assessingthe impact of these factors is complex due to the widevariation of variables.

This article summarizes the lessons learned from more than100 deployments in wells equipped with multiple downholevalves. These lessons illustrate the advantages of theseapplications and should provide insight for improvedperformance. As there is no “one size fits all,” proper designshould be emphasized for maximum effectiveness.

INTRODUCTION

This article documents the findings, results and recom -mendations of the evaluation of more than 100 intelligentwells equipped with multiple downhole valve installations inSaudi Aramco. The downhole valves are usually referred to as

“Inflow Control Valves,” (ICVs) “smart” or “intelligent”completions. The ICVs are multi-position active downholevalves that can be controlled from the surface. The concept ofthis technology was developed to provide a means to optimizeproduction, and provide zonal isolation and flow control ofcommingled production from different laterals or segments.Using the variable positions of these valves, production can bemanaged in real time to improve oil performance. Thesedownhole valves are accessories for maximum reservoircontact (MRC), multilateral or multisegmented horizontalwells to manage production, where there is:

• High reservoir pressure variation among laterals orsegments.

• Significant variation in productivities between laterals.

• Varying gas/water fractions among laterals or segments.

• A presence of fractures, faults and/or high permeabilityintervals.

The first deployment of this technology took place in 2004across Saudi Aramco fields; mainly Shaybah and Haradh-IIIfields, with the majority installed in MRCs and multilateral wells.These technologies are used as fit-for-purpose. They are custom-designed to take into account reservoir characteristics, com pletionarchitecture, and operational and economic measures.

The effectiveness of these completions depends on theproper planning, design and placement of laterals or seg ments.The presence of an integrated system, including surface panelsand multiphase testing capabilities, is a key factor toeffectively utilize ICVs.

This article provides an assessment of wells equipped withsurface-controlled downhole ICVs, focusing on their impacton well and reservoir performance and development cost.Results have proven that these completions have been effectivein sustaining oil rates, controlling water production,minimizing or eliminating water and gas production andreducing development cost.

EVOLUTION OF APPLICATION OF DOWNHOLE VALVESIN SAUDI ARAMCO

The first implementation of these completions in SaudiAramco took place in conjunction with multilateral MRCwells in early 2004. Encouraging results from the MRC and

Lessons Learned from 100 Intelligent WellsEquipped with Multiple Downhole Valves

Authors: Saeed M. Al-Mubarak, Naseem J. Al-Dawood and Salam P. Salamy

Fig. 1. Evolution of intelligent wells equipped with downhole valves in Saudi Aramco.

2004 2005 2006 2007 2008

Birthof Smart(7” Liner)

Smart(ML/Expandable)

Smart(ML/Open Hole)

(ML/MPFM)

Smart(SL/Open Hole)(ML/Slim Hole)(SL/Slim Hole)

EVOLUTION OF INTELLIGENT WELLS WITH ICVS

SAUDI ARAMCO JOURNAL OF TECHNOLOGY FALL 2009 3

multilateral wells triggered the need to optimize and manageproduction from different laterals. This need was translatedinto piloting downhole ICVs.

Approval of the ICVs concept was achieved when theanticipated benefits were realized by monitoring the actualperformance of these wells. The leveraged knowledge hasprovided an insight into the ICVs’ capabilities andimplementation. Moreover, it has set the stage for thedevelopment of Haradh Increment-III exclusively with MRCwells equipped with ICVs1.

The concept has not been limited to new wells. Theutilization of ICVs has been extended to enhance performanceof existing weak and dead conventional wells after convertingthem to MRCs and multilaterals.

The technology even extended to target single lateral newhorizontal wells where downhole valves were installed acrossthe horizontal section. Moreover, the good results have led totrying new downhole technologies, such us permanentdownhole multiphase flow meters (MPFMs). In Well A2, atrilateral well, every downhole valve was combined with aMPFM and permanent downhole pressure and temperaturegauges. The latest implementation was tailored to targetexisting dead wells where slim hole multilaterals and singlelaterals were drilled and equipped with downhole valvesacross their open hole.

OVERALL FINDINGS

Field performance of wells equipped with ICVs has indicatedevident advantage over conventional completions. The ICVshave been very instrumental in meeting both reservoir andproduction main objectives, such as sustaining wellproductivity, improving sweep, controlling production ofmultiple laterals, managing water production and minimizingproduction interruptions.

These advantages were more pronounced in fields that weredeveloped with infrastructures that allow real-time remotemonitoring and controlling capabilities3, as will be illustratedin the coming sections of this article.

PRODUCTIVITY VARIATION AMONG LATERALS

Several multilateral wells equipped with downhole valves arelocated in an area characterized by high productivityvariations among different laterals. These variations areinfluenced by reservoir properties and wellbore andcompletion characteristics. In the case of homogeneousreservoir environments, field data has indicated that the closerthe lateral is to the heel, the higher the productivity, Fig. 2.This is due mainly to the pressure drop resulting from frictionlosses. Figure 3 illustrates a schematic of a quadrilateral wellwith its laterals labeled by MB, L-1, L-2 and L-3.

Optimizing the production of these wells necessitatesregulating the settings of downhole valves in accordance withthe laterals’ productivities, and is in alignment with overall

production strategy of the well and the area. During theoptimization, downhole valves and surface choke4 adjustmentsare performed to accomplish one of several objectives:minimizing drawdown, maximizing total production,minimizing water production or equalizing production amongthe laterals. It is fair to say that there is no “one-size-fits-all”approach. In any optimization scenario, options are rankedaccording to the possibility of accomplishing the desired target.Field optimization efforts have been performed for severalwells honoring various objectives (i.e., less water production,balanced contribution, etc.).

PROLONGING WELL LIFE

Well A, a multilateral well, has demonstrated the power ofICVs in prolonging well life and eliminating water production.The multilateral well is located in a heterogeneous areacharacterized by irregular water movement due to thepresence of fractures and high permeability layers. Once thewell started to produce water, managing production amongthe laterals became more important. The production of thiswell was managed and maintained by changing downholevalve positions to eliminate water production that killed thewell when the downhole valves were fully open1.

Managing Withdrawal and Optimizing Sweep

Well B, a multilateral well, is located in an area withcontrolled injection and uniform sweep. The well’s target, setto be 10 thousand barrels of oil per day (MBD), is in full

Fig. 2. Productivity variation among laterals at similar ICV positions.

Normalized Lateral Rates(Choke Setting #3) 1.50

1.251.15

1.00

MB L-1

0.3

0.0

0.6

0.9

1.2

1.5

L-2 L-3

Fig. 3. Schematic of quadrilateral well equipped with four ICVs.


positions before and after, where ICV setting 10 reflects a fullyopen ICV and setting 0 represents a closed valve. Figure 6shows the production rate and flowing bottom-hole pressure(FBHP) before and after. In this particular well, theoptimization of the downhole valves was done in conjunctionwith additional control by use of a surface choke5.

Management of Withdrawal in Homogeneous Reservoirs

The examples mentioned in the previous section indicatehow downhole valves have contributed to manageproduction, and improve performance and rate inheterogeneous reservoirs. This example discusses Well D, atrilateral that is located in a homogeneous reservoir. Theobjective was to produce the well at the lowest possiblepressure drawdown from all the laterals; therefore delayingboth water and gas breakthroughs. Pro duction testsindicated that every lateral was produced at a rate of ~ 9MBD at a fully open surface choke setting. The well was puton production at a rate of 10 MBD by adjusting the surfacechoke, allowing laterals to produce at a lower drawdown asdetailed in Table 2.

alignment with reservoir production strategy. With theseobjectives in mind, comprehensive rate tests with severaldownhole choke setting combinations were conducted.

Test results indicated that the upper lateral dominates theflow due to its higher productivity and the higher reservoirpressure in the area, Fig. 4.

The final configuration of the downhole valves’ settingswas adjusted so that all laterals are producing at about thesame rate. Using the surface choke, the total withdrawal ofthe well was restricted to an oil rate of 10 MBD and 0%water cut. Since then, the well has been producing at this ratewith no water production. Figure 5 shows the ratedistribution of the laterals after the adjustment of thedownhole valves at optimum settings.

Maximizing Production Rate

Well C is a trilateral well that was producing oil at a rate of8.5 MBD at very high drawdown with all of its downholevalves fully open. A comprehensive test was conducted on thewell at several downhole choke setting combinations. Resultsagain indicated that the upper lateral (L-2) was dominatingthe flow. Having an assigned target rate for the well andknowing the reservoir performance around its three laterals,the downhole choke settings were adjusted to maximize therate yet reduce drawdown. Table 1 indicates the valve

Fig. 4. Upper lateral domination inflow when downhole valves fully open.

012345678

MB

2.5

L1

2

L2

8

Rat

e (M

BD

)

Fig. 5. Balanced inflow distribution at valve positions 10 for MB, 10 for L1 andfour for L2.

0.0MB L1 L2

0.5

1.0

1.5

2.0

2.5

3.0

3.53.5 3.5

3.0

Rat

e (M

BD

)

Fig. 6. Rate and FBHP before and after optimization settings of ICVs.

0

3

6

9

12

15

8.6

Before After

Rat

e (M

BD

)

FBHP1,927 psi

FBHP2,296 psi

13.2

Table 1. ICV settings before and after

Lateral Initial ICV Setting Final ICV SettingL-0 10 10L-1 10 5L-2 10 4

Table 2. Well D rate test at various ICVs and surface choke settings

Well D (Trilateral MRC with ICVs) Tested Downhole FWHP, Rate,Lateral Choke psi MBOD

Lateral 1 100% 1,017 9.3 Lateral 2 100% 1,044 8.9

Motherbore 100% 1,036 8.7Surface FWHP, Rate,Choke psi MBOD

All 25% 1,086 10 All 35% 895 16

months. These routine tests can be done more easily in fieldswhere surface infrastructure allows testing and optimizationby either a permanent or portable surface control or testingunit. With the lack of dedicated testing facilities and surfacecontrol systems for each of the smart wells, it is extremelyhard to optimize the performance of these wells; therefore, theexpected benefits of such wells cannot be fully realized.

In another aspect, field data has confirmed that after fouryears of deployment, the systems are functional in controllinginflow from laterals, and that the flow characteristics of thedownhole valves are varied due to different completion designsand productivity indexes of producing zones. This makes thedesign and capabilities of the downhole valves essential toaccomplish the desired objectives. Figure 8 illustrates downholecapabilities across various operating conditions. Assessments andefforts were made to improve the design of the downhole valves.The new design provides a higher level of control at lower flowrates, enabling finer adjustment of the distribution of inflowamong different laterals or segments that shall allow bettermanagement of wells and will satisfy the production strategy7.

Field data indicated equivalent flow contribution amongdifferent laterals when wells produce dry oil, mainly in wellswith minimum variations in reservoir quality. When water orgas breaks through in any lateral, ICVs become essential inmanaging withdrawal among different laterals to minimize oreliminate water or gas production.

Minimizing Cross Flow among Laterals in HeterogeneousReservoirs

Due to the heterogeneity of some reservoirs and the presenceof differential pressure among laterals, the efficient utilizationof ICVs is required to manage withdrawal. A production logon Well E, one of the first trilateral MRC wells equipped withsliding sleeve controls, was run to determine lateral con -tributions, well performance, and to detect any waterpresence. Logging results indicated cross flow among thelaterals at different surface choke settings and while the wellwas shut-in. Even if the cross flow is expected, it is notaccepted for good reservoir management practices as crossflow between a wet and dry lateral could be damaging to wellproductivity, due to rock imbibitions of water. In this well, thecross flow was eliminated when the well surface choke was setat 102/164, Fig. 76.

Similar cross flow was detected in a trilateral well equippedwith downhole valves and downhole MPFM2. Theseoccurrences of cross flow can be reduced or eliminated byimplementing an active multi-position ICV system or othertechnologies that can prevent or minimize cross flow amonglaterals or segments. With these facts in mind, the func -tionality of ICVs becomes an integral part in managing thewithdrawal from MRC or multilateral wells.

Downhole Valves Functionality and Capabilities

One of the adopted strategies when installing any of thesecompletions is to make sure that all the ICVs are functionalwhile the rig is on location. To date, the overall deploymentsuccess rate is close to 100%. Once a completion is set and awell is put in production, it is expected that these completionsare routinely function tested in periods not exceeding six


Fig. 7. Surface choke settings eliminates cross flow by optimizing choke setting.

Fig. 8. Downhole valve capabilities vary according to reservoir rock and fluidproperties.


fields. The group benefits by having multiple members keeptrack of changes and detect errors before they escalate.

This environment can be facilitated by establishingstandards for ICVs, their surface control infrastructure andtheir remote control capabilities. When designing an ICVcontrol room, it is necessary that the technologies usedsatisfy the following criteria:

• Affordable: Low-cost deployment strategies and on-demand solution accessibility.

• Available: As real time control becomes more strategicto the business, the cost of downtime increases.

• Scalable and high performance: Business usersincreasingly demand sophisticated real time testing andcontrol functions. These requirements, coupled withperformance and reliability, are essential.

• Supportable and manageable: These technologies mustbe usable and reliable.

• Compatible: Should be fully functional for all commonICV systems.

• Specialized expertise: A business unit with requiredexpertise is required to run the center and conduct alltests and optimization according to predefinedobjectives.

• Secure and compliant: It’s essential that a solutionprovide a trusted, secure environment in which toconvey confidential business information.

CONCLUSIONS

Advanced well completions have opened up numerousimprovement opportunities. Earlier implementations ofdownhole valves have demonstrated their advantages overconventional completions. In this article, we have discussedthe performance of surface controlled downhole valves andtheir impact on well performance. Moreover, it sheds lighton potential improvements to ensure continuousimprovement in their design and performance. The mainconclusions are:

• The actual performance of wells equipped withdownhole valves exceeds that of conventional wells.

• There is no “one-size-fits-all” completion scheme. Theyare designed as fit-for-purpose. It is essential to evaluateavailable completion capabilities with regard toreservoir properties and well configuration, welllocation and requirements prior to installation.

• The success of optimization of these completionsdepends upon the ability to facilitate operating thesewells at their optimum performance level to be able toimprove the overall asset value.

• Operational experience with MRC and multilateralwells equipped with ICVs is still maturing. The

POTENTIAL IMPROVEMENTS

Cross Flow Prevention

The occurrence of cross flow between laterals or segments isnot always preventable with the current ICV designs. Whenlaterals experience differential pressures, they are vulnerableto cross flow. When a well is shut-in, cross flow can beprevented either by closing all the ICVs or equipping thecompletion with a cross flow preventer that is triggeredwhenever cross flow occurs.

ICV with Multiple Downhole Gauges

Most of the available completions do not provide values forupstream or downstream pressures across downhole valves.Optimizing the performance from these completionsrequires rigorous testing for every lateral or segment. Suchintensive testing can be eliminated if each ICV is equippedwith multiple downhole gauges capable of reading both theupstream and downstream pressures across an ICV. Thereal time pressure measurements will facilitate:

• Optimizing the production of each lateral by setting theICV at an optimum position.

• Identifying the occurrence of cross flow, therebyminimizing or eliminating cross flow.

• Calculating the total rate from each ICV (knowing thedelta pressure and flow area).

• Providing a reservoir pressure reading when the valvesare closed.

Requirements for Full Utilization

For the purpose of having all the requirements met for fullutilization of these completions, a set of roles and responsi-bilities need to be established to ensure maximum utilizationof these technologies. The maximum utilization of thesecompletions will result in operating these wells at theiroptimum performance, and therefore, improve the overallasset value. The requirements for full utilization willincorporate:

• Ability to remotely control downhole inflow controldevices.

• Accessibility to testing facilities (surface or downhole).

• Optimization procedures.

• Capability of modeling (reservoir and wellbore).

• Integrated system (subsurface to surface).

ICV Control Room

One of the recommendations is to have control over allinstalled ICVs from a dedicated center. The center wouldrequire a real time collaboration environment, expertoperators and remote control over all installed ICVs in all

evaluation has nurtured an accelerating learningenvironment, which leads to a better understanding ofthe existing ICV capabilities.

ACKNOWLEDGMENTS

The authors wish to thank Saudi Aramco management fortheir support and permission to present the informationcontained in this article. In addition, the authors would like toextend their appreciation to the Petroleum EngineeringTechnology Assessment Team members.

REFERENCES

1. Mubarak, S.M., Pham, T.R. and Shafiq, M.: “UsingDownhole Control Valves to Sustain Oil Production fromthe First MRC, Multilateral and Smart Well in GhawarField: Case Study,” SPE paper 120744, SPE Productionand Operations Journal, November 2008, pp. 427-430.

2. Arnaout, I.H., Al-Buali, M.H., Mubarak, S.M., Johansen,E.S., Zareef, M.A. and Ünalmis, Ö.H.: “OptimizingProduction in Maximum Reservoir Contact Wells withIntelligent Completions and Optical Downhole MonitoringSystem,” SPE paper 118033, presented at the Abu DhabiInternational Petroleum Exhibition and Conference, AbuDhabi, U.A.E., November 3-6, 2008.

3. Mubarak, S.M.: “Real-time Reservoir Management fromData Acquisition through Implementation: Closed-LoopApproach,” SPE paper 111717, presented at the IntelligentEnergy Conference, Amsterdam, SPE The Netherlands,February 25-27, 2008.

4. Konopczynski, M. and Ajayi, A.: “Design of IntelligentWell Downhole Valve for Adjustable Flow Control,” SPEpaper 90664, presented at the SPE Annual TechnicalConference and Exhibition, Houston, Texas, September 26-29, 2004.

5. Arnaout, I.H., Driweesh, S.M. and Zaharani, R.M.:“Production Engineering Experience with the First I-FieldImplementation in Saudi Aramco at Haradh-III:Transforming Vision to Reality,” SPE paper 112216,presented at the SPE Intelligent Energy Conference,Amsterdam, The Netherlands, February 25-27, 2008.

6. Mubarak, S.M., Afaleg, N.I., Pham, T.R., Zeybek, M. andSoleimani, A.: “Integrating Advanced Production Loggingand New Wellbore Modeling in a MRC Well,” SPE paper105700, presented at the Middle East Oil Show, Bahrain,March 11-14, 2007.

7. Mubarak, S.M., Sunbul, A.H., Hembling, D., Sukkestad, T.and Jacob, S.: “Improved Performance of Downhole ActiveInflow Control Valves through Enhanced Design: CaseStudy,” SPE paper 117634, presented at the Abu DhabiInternational Petroleum Exhibition and Conference, AbuDhabi, U.A.E., November 3-6, 2008.



BIOGRAPHIES

Saeed M. Al-Mubarak is a Supervisorin the Southern Area ReservoirManagement Department and aspecialist in Real-Time ReservoirManagement (RTRM) and IntelligentFields (I-Fields). He has been veryinvolved in the development, the design

and the implementation of I-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 the Society of Petroleum Engineers(SPE) Distinguished Lecturer in RTRM during 2009-2010.Saeed received the 2009 SPE Regional Award forManagement and Information.

In 1992, he received his B.S. degree in ChemicalEngineering from King Fahd University of Petroleum andMinerals (KFUPM), Dhahran, Saudi Arabia, and is nowfinishing his M.S. degree in Petroleum Engineering from thesame university.

Naseem J. Al-Dawood is currentlyacting as the General Supervisor ofthe Khurais Reservoir ManagementDivision of the Southern AreaReservoir Management Department.He joined Saudi Aramco in 1993 andhas worked in various disciplines,

including reservoir management, reservoir description,and production and drilling engineering. Naseem has heldvarious reservoir management supervisory positions andhas carried out and led many reservoir related studies,including a team exploring opportunities to enhancewells and field performance through advanced wellcompletion technologies.

He received his B.S. and M.S. degrees in PetroleumEngineering in 1990 and 1992, respectively, both from theUniversity of Alabama, Tuscaloosa, AL.

Salam P. Salamy is a PetroleumEngineering Consultant for SaudiAramco with over 20 years of industryexperience. He is currently holding theposition of Assistant to the ExecutiveHead, Petroleum Engineering &Development. Salam joined Saudi

Aramco in 1996 as an Engineer in the ReservoirManagement Department on the Shaybah Field Project. Hehas held several reservoir management supervisory positionsincluding at the Shaybah, Berri and Safaniya Fields. Prior tojoining Saudi Aramco, Salam worked with the U.S.Department of Energy, BDM International Oil and GasDivision and the U.S. National Institute of PetroleumEnergy Research (NIPER). His experience was primarily inthe area of horizontal well technology. Salam is the authorand co-author of over 25 technical publications.

Salam was the Society of Petroleum Engineer (SPE)Distinguished Lecturer for 2004-2005 and a KeynoteSpeaker at several SPE Forums and Workshops. He servedas the 2003-2004 SPE Saudi Arabia Section Chairman andwas the 2002-2003 SPE Saudi Arabia Section Program Vice-Chairman. His awards include the 2006 Middle EastRegion Service Award and the 2009 SPE DistinguishedMember Award.

In 1982, he received his B.S. degree, and in 1985, hereceived his M.S. degree, both in Petroleum and Natural GasEngineering from West Virginia University, Morgantown, WV.

ABSTRACT

Over the past decades, environmental regulations for oil andgas companies have become increasingly more stringent toprotect and preserve the environment for future generations.This is particularly true for remote areas and environmentallysensitive terrestrial and marine locations where there is astrong emphasis on protecting natural habitats and resources.Accordingly, many regulatory agencies have adopted “zerodischarge” policies requiring all generated wastes to bedisposed of in a responsible manner. For drilling operations,the various waste streams that need to be handled anddisposed of properly include: drill cuttings, excess drillingfluid, contaminated rainwater, produced water, scale,produced sand, and even production and cleanup waste. Oldpractices involve temporary box storage and hauling of thewaste products to a final disposal site. Often these sites areseveral kilometers (km) away from the generation source,creating not only liabilities for the operating company, butalso envi ronmental risks from accidental releases and gasemissions that result in higher operating costs.

To address these concerns, waste management technologieshave evolved to offer cuttings re-injection (CRI) as a safe andcost-effective alternative that permits the permanent andcontained disposal of drilling cuttings in an engineering-determined subsurface formation. Cuttings re-injectionprovides a secure operation achieving “zero discharge” byinjecting cuttings and associated fluids up to several thousandmeters below the surface into hydraulically created fractures.This disposal technique mitigates any surface environmentalrisks and future liabilities for operating companies.

Saudi Aramco has taken the initiative to utilize CRI as thepreferred technology to manage drilling wastes that will begenerated in the Manifa field development. To minimize risksassociated with CRI and conduct successful injectionoperations, an Assurance Waste Injection Process was set inplace to continuously monitor the operation and plan aheadfor any eventuality. Assurance of the injection operationbegins during the planning phase with a comprehensivefeasibility study based on existing data. Simulations areperformed for the anticipated downhole waste domain toensure containment within the selected formation and permitadequate design of surface facilities for the particular project.

This article describes the various components of the firstSaudi Aramco CRI pilot study. These include: reservoir/geomechanical data analysis and interpretation; preliminarygeomechanical modeling; target zone selection; test welldesign, drilling and injectivity testing; and geomechanicalmodel refinement using field injectivity data. The objectivesof this study for the Manifa field development project wereto evaluate:

• What are the most promising zones for injection basedon the geomechanical model?

• Do overlying formations provide effective containmentof the injected wastes?

• What are the injection rates, volumes, slurry rheology,and particle size requirements for field testing?

• What were the results of the field injectivity testing atMNIF-ABC?

• What are the long-term, predictive results from re-calibration of the geomechanical model?

• What is the well design and completion strategy duringthe implementation phase?

INTRODUCTION

The Manifa field is an offshore field that lies mainly inshallow water, up to 40 ft in depth. The Manifa field wasdiscovered in 1957 and production began when the Manifareservoir came onstream in 1964.

The Manifa field is a northwest-southeast trending anticlineand measures approximately 28 miles (45 km) in length and11 miles (18 km) in width. There are six oil-bearing reservoirsin Manifa: Upper Ratawi, Lower Ratawi, Manifa, and Arab-A, B and C/D. The reservoirs for increment development arethe two most prolific reservoirs, the Lower Ratawi andManifa reservoirs, Fig. 1.

The Manifa and Lower Ratawi reservoirs are primarilylimestone with occasional dolomitic intervals and generallyexhibit high porosity and permeability. The reservoirs weredeposited in a shallow marine carbonate platform capped bytight lime mudstones and algal bounds tone facies. A continuoustar mat underlies the oil column in both reservoirs thateffectively separates the oil column from the aquifer.


Drill Cuttings Re-Injection (CRI) Assessmentfor the Manifa Field: An Environmentally Safe and Cost-Effective Drilling WasteManagement StrategyAuthors: Yousef M. Al-Shobaili, Kirk M. Bartko, Philip E. Gagnard, Mickey Warlick and Ahmad Shah Baim


important during the selection of tentative injectionpoints. The stress contrast acts as a barrier to avoiduncontrolled vertical growth during the CRI operation.Additionally, that contrast can reduce the horsepowerneeded to fracture the formation, and consequently, helpto reduce the operational and maintenance cost.

• High Leakoff Zone: Formations with high leakoff inupper layers provide a barrier to prevent uncontrolledvertical growth during the operations. The dehydrationof the slurry causes premature screen out on top, whichinduces the storage of the cuttings in the upper area,and prevents the propagation in a vertical direction.Identification of the high leakoff zone is important incases where no stress contrast is identified.

• Lithology: The selection of a candidate injection zoneincludes the analysis of the lithology composition of theanalyzed formations. For CRI operation, it is desirableto inject in a formation that is easy to fracture, thatwill not have any interaction with the slurry injected,and that possesses a good storage capability that allowsthe injection of a considerable waste volume. Ingeneral, sandstone formations are the most suitable forcuttings disposal. The physical rock properties ofsandstone allow easier fracturing compared with shale,and it is not reactive with the slurry made for the CRIoperation. Also, it is important to identify the targetedarea containing a proper containment formation abovethe CRI site. It must have the required sealingproperties that assure that the injected waste willremain in the selected area, avoiding any unwantedmigration of the slurry injected. These containmentzones generally are shales with very low permeabilityand very high stress levels.

• Reservoir Depth: The location of the interest zone/payzone needs to be taken into consideration. It is notdesirable to have interferences between the “Target”injection zone and the production zone. The feasibilitystudy analyzes and ensures that the waste injectiondomain will remain away from the reservoir area, toprotect the future production of the field.

MECHANICAL PROPERTY LOG

The vertical stress was estimated by integrating the availablebulk density with respect to depth. A pore pressure gradient of0.497 psi/ft was used from 6,000 ft; above 6,000 ft it wasassumed a normal pore pressure gradient of 0.433 psi/ft. Theminimum horizontal stress was estimated based on the elastictheory, assuming an isotropic environment and no externalstresses in the area.

Dynamic measurements of elastic moduli are derived frommeasuring acoustic velocities and the bulk density of thematerial. It is important to calibrate the computed dynamicelastic properties of the rock against the static rock properties

RESERVOIR EVALUATION

The objective of this task was the evaluation and determination ofthe mechanical and petrophysical properties of the formations andlithologies present in the Manifa area. These data were used toevaluate the suitability of a subsurface formation for safe disposalof waste drilling cutting slurry. This task included detailed analysisand interpretation of available well log data. A detailed reservoirevaluation helped identify the waste containment and fracturebarrier capability of a formation above the injection point thatcould prevent uncontrolled fracture vertical growth.

Geomechanical Model

Evaluation and analysis of appropriate logs were performed todetermine elastic modulus, Poisson’s Ratio (PR) properties andpossible fracture gradients of the different formations. Fluid leak-off coefficients for the disposal formation and other lithologies inthe overburden were characterized. The information wasemployed to formulate the geomechanical model used for thehydraulic fracturing simulations. The simulations are performedto provide containment assurance and predict fracture extent andbehavior in the specified conditions.

While modeling the injection zones, important factors weretaken into consideration:

• Containment Assurance: The identification of a goodcontainment is crucial for the success of the cuttings re-injection (CRI) operation. The following scenarios providegood indications for the proper storage of cuttings.

• Stress Contrast: The identification of stress contrastbetween the injection zone and the overburden is

Fig. 1. Stratigraphic location.

taken from the actual measurements of the core material beingstressed in the laboratory.

Poisson’s Ratio

Poisson’s Ratio is the ratio of the lateral strain to thelongitudinal strain. It represents the amount the sides of acube are compressed.

Young’s Modulus

Young’s Modulus (YM) is the ratio of the applied stress to thelongitudinal strain or the rock “stiffness.” This variable is animportant variable as it impacts the fracture geometry.Dynamic elastic moduli correlations were calibrated againststatic moduli obtained for the core analysis. As a result of thisanalysis, the following corrections were made:

Shuaiba Formation:YMstatic = 0.542*YM-dynamic + 586PRstatic = 0.665*PR-static + 0.16 Khafji Formation:YMstatic = 0.8278*YM-dynamic - 667PRstatic = 0.5348*PR-static + 0.171Safaniya Formation:YMstatic = 10.721*YM-dynamic + 300PRstatic = -1.463*PR-static + 0.549

The MNIF-XYZ compressional and shear sonic log datawas used to develop a mechanical property log for estimatingfracture height growth and net pressure in the three potentialinjection intervals: Safaniya, Khafji and Shuaiba formations.The minimum stress calculated from the sonic data indicateslittle stress contrast within the formation of interest. This isexpected in a high permeability environment having clean,low modulus rock throughout the interval. Because of thislittle stress contrast, the fracture geometry will be dependenton the Young’s Modulus contrast of the formation.

The lithologic characteristics of the lower Aruma shaleand Wasia formations suggest these zones are suitable forCRI. A high leakoff area is known to exist, and wasidentified in the lower part of Aruma where natural fissuresoccur in the limestone at 4,000 ft. This increase inpermeability makes an excellent barrier for preventinguncontrolled fracture height growth. High stress contrast ontop of the Lower Aruma Shale (LAS) formation also providesa good containment barrier for the underlying injection zone.Additionally, a cap rock of anhydrite in the Rus formationensures the waste would not reach the surface. All thesefeatures are presented in Fig. 2.

Based on the analysis discussed, four possible injection pointswere identified. The bottom of the LAS formation constitutesone of those selected injection zones. This point is located at5,180 ft under the high stress contrast presented in that area.This condition would provide fracture height control.

The Safaniya and Khafji members of the Wasia formationalso constitute suitable zones for injection purposes. Bothformations consist of shaly-sand lithology, and the low fracturegradient (FG) of this type of lithology makes for suitableoperations. Two injection points were recognized in the Khafjimember at 6,320 ft and 6,730 ft, respectively; however, to takeadvantage of the entire thickness of the Khafji, injection at6,730 ft was selected as the main injection point. The injectionpoint at 6,320 ft could provide another suitable place forcuttings disposal in case of any contingency event.

FLUID PROPERTIES

Fluid properties used for the injection model were based on anAberdeen and North Sea1 fluid slurry mixture. This fluid issimilar in nature to what several other operators have used inpublished SPE papers. The requirement of an injection fluid isto have sufficient viscosity to carry the solid cuttings. Table 1provides the fluid rheology used for this study along withothers for comparison.

All fracture models require a fluid with filter cakecapabilities that are governed by fluid loss. This number can becalculated in the field based on the fluid efficiency of the totalfracture system after the minifrac. This number would be an


Fig. 2. Containment assurance.

Fracture GradientsFracture GradientsGamma Ray

Fig. 3. MNIF-ABC location.


0.0005 ft/sq-min to 0.0009 ft/sq-min while the tighter Shuaibaindicated laboratory leakoffs ranging from 0.0003 ft/sq-min to0.0005 ft/sq-min. Other studies have suggested that slurryleakoff tests for high permeability sands, in both field andlaboratory measurements, have leakoff values from 0.004 ft/sq-min to 0.005 ft/sq-min2, 3. For low permeability formations,

average number of the fines concentration in the fracture.Leakoff tests in the laboratory were performed with actualcuttings. The slurry was xanthum-based polymer with 20%cuttings. Results from the laboratory leakoff tests for the threeintervals are shown in Table 2. For the high leakoff zones (i.e.,Safaniya and Khafji), the laboratory based leakoff ranged from

Fig. 4. CRI injection test process.

600 bbl Injection Test

Identify Injection

Zones

Perforate 100 ft

7” Casing Guns

at 12 SPF

Establish Injection with Clean Brine

NoPerform Acid

Treatment

1,200 bbl Injection Test



Obtain Closure Pressure




Obtain Fracture Extension Pressure

Obtain Near Wellbore Pressure Losses

Yes

Step-

Rate/Down

Test

such as shales, the leakoff coefficients range from 0.0005 ft/sq-min to 0.0006 ft/sq-min4, 5 measured from field slurry tests.

FIELD TEST

MNIF-ABC, a land based well, Fig. 3, was selected toevaluate the feasibility of CRI into selected target zones todetermine the most promising zones for injection of drillcuttings from the proposed offshore platform wells. The CRIinjection test process, Fig. 4, was applied to the fourinjection intervals to determine fluid leakoff, minimum stressand fracture extension pressures. The multiple injection testsevaluated short- and long-term injection cycles. Thesemultiple tests provided an understanding of the fluid leakoffcharacteristic over time, and the injection pressure based onan increase in slurry volume injected into the formation. Themultiple injection tests also established an injection rate andpressure history that will be used later to determine thecompletion strategy: annular vs. tubing injection.

All four formations, with the exception of the Safaniyaformation, clearly showed fracture extension and closurepressure based on the step-rate and pressure falloff. Figure 5shows a typical injection test that was performed. Thisparticular test was in the Aruma formation where threeinjection tests were performed pumping 300 bbl, 600 bbl and1,200 bbl at three barrels per minute (bpm).

The injection test in the Safaniya formation was curtaileddue to the excessive breakdown pressure and the formationsand flowback into the wellbore. The Shuaiba formationfracture extension pressure and predicted closure pressurewas correctly predicted. The Khafji closure pressureprediction was higher than the actual closure pressure,which was probably due to the Khafji being highlypermeable and friable. The Aruma calculated closurepressure was higher than predicted. The complete results ofthe pressure analysis based on the injection tests aretabulated in Table 3.

FRACTURE MODEL PRESSURE MATCHINGDISCUSSION

The modeling effort to determine the fracture geometry ofthe cuttings was performed with a fully three dimensionalfracture model. The model is a fully numerical solution for


Table 3. Pressure analysis results•*MNIF XYZ MI study prediction.•** Pressure falloff time was not sufficient.•All pressures are bottom-hole unless identified as surface.

Formation Maximum Extension Fracture Fracture Fracture Predicted* Predicted*Surface Pressure Extension Closure Closure Fracture FracturePressure (psi) Pressure Pressure Pressure Closure Closure

(psi) Gradient (psi) Gradient Pressure Pressure(psi/ft) (psi/ft) (psi) Gradient

Aruma 2,000 4,125 0.86 4,083 0.83 2,757 .71Khafji 2,800 4,557 0.69 3,828 0.58 4,578 0.71Shuaiba 2,800 5,610 0.79 NA** NA** 5,391 0.79

Fig. 5. Aruma CRI injection test.

Aruma CRI Injection

3500

3600

3700

3800

3900

4000

4100

4200

4300

4400

0 100 200 300 400 500 600 700 800 900 1000 1100 1200 1300 1400

Time (min)

Bot

tom

hole

Pre

ssur

e (p

si)

300 bbl FOT 600 bbl FOT 1,200 bbl FOT

4 bpm

Rate Loss

Step-Rate/Step-

Pext*=4130 psi

* Uncorrected for Gauge Depth

Pclosure = 3,998 psi

Pres=2,700 psi

Table 1. Fluid rheology data

Field Specific n’ k’ Viscosity Gravity (cp)

Aberdeen Fluid 1.04 0.7 0.0051 71.5Ekofisk Fluid 1.04 0.22 0.641 1280

Linear #30 HPG 1.04 0.55 0.007 54.3

Table 2. Laboratory based fluid leakoff and spurt loss

Formation Porosity Permeability Leakoff Coefficient Spurt Loss (md) (ft/min2) (gal/100 gal)

Safaniya 34 9,500 9.06E-4 7.8Khafji (Plug 1) 24 2,240 5.62E-4 3.6Khafji (Plug 2) 24 2,240 8.19E-4 2.5Shuaiba (Plug 1) 16 0.5 3.21E-4 1.6Shuaiba (Plug 2) 16 0.5 5.52E-4 0


from 30 ft to 300 ft. The Aruma was a much harderformation and showed the greatest length of 350 ft.

COMPLETION STATEGY

The offshore Manifa wells will require the wellbore to be at ahigh angle (< 30°) through the proposed injection zone targetto reach the well’s primary objective in the Manifa and LowerRatawi formation. The well will be drilled in a spider pattern,resulting in a quantity of the wells oriented in the wrongdirection to the maximum stress. Incorrect well orientationwould result in excessive treating pressures and multiplefracture generations. To reduce these impacts, plus thepossibility of the cuttings falling out on the low side of thepipe, it was recommended that the slurry be pumped downthe tubing string vs. annular injection. The tubing injectionreduced the risk of not being able to inject in this interval overtime. This provides the opportunity to clean out the pipe withcoiled tubing and add additional perforations if the formationwill not accept slurry.

The final proposed well design provides a well where theslurry can be injected down into the 4½” tubing, and then

two dimensional fluid-flow/proppant-transport calculationsand a rigorous Finite Element Method (FEM) solution forfracture width/propagation in a layered formation withvarying moduli. Net pressure matching was performed onall three successful injection zones. The Aruma and Shuaibaformation resulted in the best pressure match, requiringminimal change to the geomechanical model developed forthese two formations. The Khafji net pressure match wasthe most difficult and resulted in only capturing the trendand not the absolute value, Fig. 6. Further work needs to bedone in the fracture model to compensate for the soft rockfracturing and possible filtration of the slurry within theporous media.

Figure 7 shows the resulting fracture geometry based onthis match. The fracture stayed contained within theperforated interval and resulted in a fracture length of 50 ftto 100 ft. No post diagnostics were performed after the slurryinjections to confirm the fracture height; however, the netpressure plot indicates the fracture stayed contained, andgrew laterally based on the positive pressure gain throughoutthe slurry injection.

Table 4 is a compilation of the predicted geometries for thethree injection zones. All three zones showed containmentwithin the perforated interval and fracture lengths that ranged

Fig. 6. Khafji net pressure match - Lower net pressure is related to fracturing softunconsolidated sandstone formation.

Khafji CRI Net Pressure 1st FOT Test

0.1

1

10

100

1000

10000

0.1 1 10 100 1000

Time (min)

Bo

tto

m-h

ole

Pre

ssu

re (

psi

)

Net Pressure (3750) Frac Model 50 bbl Frac Model 300 bbl

Fracture ExtensionFracture Height GrowthFracture Screenout

Fig. 7. Fracture geometry prediction after 300 bbl slurry injected in MNIF-XYZ.

Fracture Penetration (ft)40 80 120 160

67.51 min

6575ft

TVD

6650

6725

Stress (psi)3950 45005050

0.0000.0050.0100.0150.0200.0250.0300.0350.0400.0450.050

Wid

th -

To

tal i

n

0.085 m/sec

Fig. 8. Planned MNIF CRI well completion.

181/8” at

LAS ± 4,800 ft.

Perf at Aruma

Perf at Khafji

133/8” at

Ahmadi ± 6,000 ft.

95/8” Liner Hanger

and Tie-back

95/8” packer

(drillable)

and seal assy on

41/2” tubing

95/8” at ± 8,500 ft.

Buwaib

PDHMS

24” at Rus

± 1,125 ft.

Table 4. Fracture model geometry prediction – 300 bbl injection period

Formation Fracture Height Fracture LengthContainment (100 ft (ft)perforated interval)

Aruma Yes 250 - 300Khafji Yes 50 - 100

Shuaiba Yes 30 - 50

down the backside into the Aruma formation, if the Khafjifails to accept all the slurry material, Fig. 8. The injectionwells will be at an inclination of not more than 30° across theinjection zone with a minimum separation of 800 ft fromnearby wells at the injection zones, and it will be possible toresume drilling to the downhole target upon completion of theplanned wells on the platform. The cuttings injection at thistime will be injected through the annular into the Arumaformation. In addition, the completion includes a real timedownhole pressure gauge for the Khafji formation, to observepressure changes during the injection cycles.

CONCLUSIONS

1. Three possible injection zones were identified based onintegrating log data, core data and geomechanical data: theLAS formation, and the Safaniya and Khafji, both membersof the Wasia formation.

2. CRI pilot field testing at MNIF-ABC was successful, andall the three selected injection zones can provide suitablecapacity for drill cutting disposal.

3. Tubing injection can be performed in all CRI zones withno problems about containment and uncontrolledfracture growth.

4. The presence of high leakoff zones in the lower part ofAruma provides assurance to control the risk ofuncontrolled height growth.

5. The cap rock in the Rus formation and the high stresscontrast in the LAS formation offer additional containmentassurance.

6. The geomechanical model is based on inferred parametersand correlations. The validation of the model is applicableonly in a certain region where it is assumed uniformproperties exist.

7. It is recommended the calibration of the geomechanicalmodel, with the proper injectivity test, be completed beforethe beginning of the CRI operations, especially if the injectorwell is far away from the wells analyzed in this report.

8. CRI well design must consider fracture pressures andinjectivity potential.

ACKNOWLEDGMENTS

The authors wish to thank Saudi Aramco management for theirsupport and permission to present the information contained inthis article. We also would like to acknowledge contributionsfrom the Manifa CRI Team Members for their valuable input inmaking this a successful test, and to Drilling and Workover forexecuting the slurry injection testing program.

REFERENCES

1. Nagel, N.B. and Strachan, K.J.: “Implementation ofCuttings Reinjection at the Ekofisk Field,” ISRM/SRMpaper 47218, presented at the ISRM/SRM Eurock,Trondheim, Norway, July 8-10, 1996.

2. Sassen, A., Tran, T.N., Joranson, H., Meyer, E., Gabrielsen,G. and Tronstad, A.E.: “Subsea Re-Injection of DrilledCuttings – Operational Experience,” SPE paper 67733,presented at the SPE/IADC Drilling Conference,Amsterdam, The Netherlands, February 27 - March 1,2001.

3. Guo, Q., Geehan, T. and Ulyott, K.W.: “FormationDamage and its Impact on Cuttings Injection-WellPerformance: A Risk-Based Approach on WasteContainment Assurance,” SPE paper 98202, presented atthe SPE International Symposium and Exhibition onFormation Damage Control, Lafayette, Louisiana,February 15-17, 2005.

4. Guo, Q., Dutel, L.J., Wheatley, G.B. and McLennen, J.D.:“Assurance Increased for Drilling Cuttings Re-Injection inthe Panuke Field Canada: Case Study of ImprovedDesign,” IADC/SPE paper 59118, presented at theIADC/SPE Drilling Conference, New Orleans, Louisiana,February 23-25, 2000.

5. Wilson, S.A., Rylance, M. and Last, N.C.: “FractureMechanics Issues Relating to Cuttings Re-Injection atShallow Depth,” SPE paper 25756, presented at theSPE/IADC Drillling Conference, Amsterdam, TheNetherlands, February 23-25, 1993.



IL. Earlier in his career, 1982-1986, he worked with theSaudi Aramco Hydrology Department. In 2000, Philip re-joined Saudi Aramco working with the EnvironmentalProtection Department. He has 30+ years of diversifiedenvironmental and waste management experience across theoil production, solid and hazardous waste, transportationand consulting industries. Philip’s career has focused ongroundwater resource impact evaluation, contaminantassessment, site remediation, terrestrial and marinehydrocarbon impacts, solid/hazardous waste management,waste treatment technologies, oil and gas industry wasteissues, and regulatory compliance.

Mickey Warlick is a PetroleumEngineering Specialist with the ManifaReservoir Management Division andhas been with Saudi Aramco for 7years. In 1981, he received his B.S. inPetroleum Engineering from the NewMexico Institute of Mining and

Technology at Socorro, NM. Mickey joined Chevron USAInc., and began work as a Reservoir Engineer in thePermian Basin located in west Texas and eastern NewMexico. There, he worked on diverse reservoirs rangingfrom shallow 2,000 ft oil reservoirs to 30,000 ft deep gasreservoirs. Mickey gained experience in working onprimary, secondary and even CO2 tertiary processes. Hethen moved to the Over Thrust area of Wyoming where hegained firsthand experience in dealing with 20% H2S gasreservoirs that required utmost safety in drilling andworkover operations. Later Mickey moved on to La Habra,CA where he worked in Chevron’s international operationsdeveloping and deploying new field technologies.

Just before his move to Saudi Arabia, Mickey transferredto Houston, TX where he worked as a Reservoir SimulationEngineer in Chevron’s International Reservoir Simulationdepartment. While in Houston, he earned his M.S. degree inPetroleum Engineering from the University of Houston,Houston, TX in 2001. Mickey joined Saudi Aramco in2002, working as a Reservoir Engineer in the Zuluf field.When Saudi Aramco decided to bring the Manifa field on asone of its major increments, he was transferred there and iscurrently Team Leader for the Manifa reservoir of theManifa field development.

Ahmad Shah Baim is a Senior DrillingEngineer in Saudi Aramco and wasfully involved in the planning of theManifa Offshore Drilling program. Hejoined Saudi Aramco in 2005 and has19 years of experience in the oil andgas industry.

In 1988, Ahmad received his B.S. degree in MechanicalEngineering from Gannon University, Erie, PA.

BIOGRAPHIES

Yousef M. Al-Shobaili is currently theNorthern Onshore Fields Group Leaderat the Reservoir CharacterizationDepartment. He joined Saudi Aramcoin 1994 after receiving his B.S. degreein Petroleum Geology andSedimentology from King AbdulAziz

University, Jiddah, Saudi Arabia. During his career he hasworked in several disciplines of the Exploration andPetroleum Engineering organizations.

Yousef’s experience covers several reservoir aspects,including reservoir evaluation and assessment, reservoirmanagement and engineering assessment, petrophysicalintegration, reserves estimation and assessment, identifyingnew hydrocarbon from old fields, drilling operations andwell planning, reservoir description, geomechanics andwellbore stability, log analysis and interpretation, and coredescription and integration. He has also trained severalsummer students, geologists, geophysicists, and reservoirengineers, and he developed an in-house log interpretationand petroleum geology training course.

Yousef has authored and co-authored 18 technical papersin reservoir evaluation, reservoir description, geosteering,rock mechanics, reservoir management and dynamics andlog/core petrophysics. He is the founder and the firstpresident of the Saudi Petrophysical Society (SPS).

Yousef attended and passed an intensive six monthpetrophysical and log evaluation Schlumberger program. Hewas the first worldwide non-Schlumberger employee to everjoin this program.

Kirk M. Bartko is a Senior PetroleumEngineering Consultant with SaudiAramco’s Petroleum EngineeringSupport Division. He received his B.S.degree in Petroleum Engineering fromthe University of Wyoming, Laramie,WY. Kirk joined Saudi Aramco in 2000

and he supports stimulation and completion technologiesacross Saudi Arabia. His experience includes 19 years withARCO with various global assignments including Texas,Alaska, Algeria, and the Research Technology Centersupporting U.S. and international operations. Kirk hasauthored and co-authored more than 36 technical papers onwell stimulation, holds a patent on monitoring fracturepressures, and has been actively involved in the Society ofPetroleum Engineers (SPE) since 1977.

Philip E. Gagnard is a PetroleumEngineering Specialist with the Drilling& Workover Services Department(D&WOSD). Currently, he is the teamleader for the Manifa Cuttings Re-Injection (CRI) Project and an activemember in the Manifa onshore waste

management efforts. In 1970, Philip received his B.S. degreein Mathematics and in 1972 his M.S. degree in GroundWater Hydrology from the University of Illinois, Chicago,

ABSTRACT

The product of reactions between steel pipelines and somespecies in processed natural gas is a significant concern to thegas industry. The corrosion product, which is a mix of ironoxides, sulfides, and carbonates, has several impacts onpipeline operations and must be periodically removed bypigging the pipeline. The difficulty in understanding themechanisms of the formation of this material comes in a largepart from the nonuniform conditions, i.e., water dew point,and H2S, CO2 and O2 concentrations in the pipeline.

This article provides an evaluation of the application ofchemical thermodynamics to the formation of this material –what is commonly known in the gas industry as black powder.Given the complex nature of the formation of black powder, itwas decided to study the formation and stabilities of variousiron phases, namely iron oxides, sulfides and carbonates, aswell as elemental sulfur in sales gas pipeline environments.

Our findings show that thermodynamics can be a usefultool to indicate what can, and cannot, possibly form underdewing conditions; however, compositional analysis of thepowder can assist in directing the calculations. Due to theseuncertainties, the results should be used as a guide to betterunderstand the corrosion mechanisms inside the pipeline.

INTRODUCTION

The product of reactions between the steel of natural gaspipelines and components in processed natural gas is asignificant concern to the gas industry. This corrosionproduct, commonly referred to as black powder, is a mix ofiron oxides, sulfides and carbonates, which causes erosion invalves and must be periodically removed by pigging thepipelines1-4. Black powder samples collected from sales gaspipelines showed only the presence of iron oxides andcarbonates, as can be seen in Table 14.

The difficulty in understanding the mechanisms forformation of this material comes from the nonuniformconditions in the pipeline. Water content and dew points, H2Sand CO2 concentrations, and the presence of oxygen will allhave a significant impact.

Since corrosion is thought to have occurred due tocondensed water (liquid phase), the dew points under several


Thermodynamic Analysis of Formation ofBlack Powder in Sales Gas Pipelines

Authors: Dr. Abdelmounam M. Sherik and Dr. Boyd R. Davis

operating conditions were calculated to determine deleteriousconditions. Furthermore, the composition and pH of suchaqueous phases were calculated using various assumptions.EpH diagrams were then generated to determine what iron ionspecies would be predominant in the aqueous environment.

One of the main challenges in the current thermodynamicanalysis was understanding, in sales gas with oxygen ingress,the predominance of iron oxide phases (magnetite-Fe3O4 andαFeOOH) in the collected black powder, knowing from theliterature5-7 that FeCO3 would be the expected dominantspecies. This is reflective of the significant complexity of thecorrosion problem resulting from changing conditions in thegas phase (such as oxygen ingress or changes in the H2S, CO2

and/or H2O levels), the effect of kinetics on the reaction ofpipeline steel with the solution, and the subsequent potentialconversion of reaction products in a dry environment (i.e., theconversion of FeCO3 to Fe3O4). An added complexity to thecurrent analysis is that the black powder samples do notrepresent black powder that has formed under well-definedconditions (specific location and time) in the pipeline. Theyinstead represent samples collected from the sum of blackpowder products that have formed at varying locations andtimes along the pipeline (i.e., water condensation might haveoccurred only at low points and for a few hours during thewinter season, or oxygen ingress takes place at low-pressurepoints, etc.). All this makes of correlating the results of thecurrent thermodynamic analysis with actual field X-raydiffraction (XRD) results quite a difficult task. This meansthat an attempt at quantitative analysis of the thermo-dynamics as they apply to the formation of black powdercould be misleading as a result of the wide range of potential

Table 1. Composition of black powder as determined by XRD technique

Main Compound Approximate Averagewt%

Magnetite-Fe3O4 60γ-FeOOH Trace amounts (< 2)α-FeOOH 25Iron Sulfides Not detectedSiderite-FeCO3 10Elemental Sulfur 5


At pipeline temperatures, methane is very kinetically stablewith respect to other gases. The extent of this stability will bedetermined in future experimental work, but it is reasonableto assume that the interaction of methane and nitrogen withother gases in the pipeline will be limited. It is not possible toconduct thermodynamic calculations with methane andnitrogen in the calculation due to this kinetic barrier toreaction (however, the reaction still takes place in thethermodynamic calculations). For this reason, it wasdetermined that CH4 and N2 needed to be removed from thecalculations and replaced with Ar so as not to impact on thereaction equilibrium. Since this article is intended to show thepotential for thermodynamic calculations as they relate toblack powder formation, this is one of the assumptions thatmust be made for this type of calculation to be done. Theresults of these calculations will be compared withexperimental work currently underway on gas phase stability.Another example of this gas phase kinetic barrier issue isCO/CO2 equilibrium. At low (under 100 ºC) temperatures,CO and CO2 can exist together at any ratio despite thermo-dynamics stating that there would be a reaction between themto make elemental carbon. CO/CO2 gas blends in cylinderscan be purchased that remain at the same ratio virtuallyindefinitely.

Oxygen can be an important factor in sales gas pipelinecorrosion. Oxygen ingress in gas lines can cause significantcorrosion in small concentrations and combustion in largeramounts. A 1988 survey of 44 natural gas transmissionpipeline companies in North America indicated that the gasquality specifications allowed maximum O2 concentrationsranging from 0.01 mol% to 0.1 mol% with typical value of0.02 mol%6, 8. It has been shown that oxygen content ofapproximately 0.01 mol% has little effect on steel corrosionin the presence of stagnant water inside sales gas trans -mission pipelines, while 0.1 mol% produces fairly high

conditions and kinetic limitations on the reactions. Although,thermodynamics can be a useful tool to predict what can, andcannot, possibly form under dewing conditions.

The fact that there is a wide range of products (iron oxides,carbonates and elemental sulfur) sampled from the pipelinesindicates that this is not a homogeneous process that iscontrolled by thermodynamics. In other words, if the gasphase is relatively constant, thermodynamics would predictone stable phase for each of the nonmetallic components inthe gas phase (i.e., S and C). The fact that there are all theabove mentioned phases present means that there are regionsof kinetic control in the pipeline. Thermodynamics can be auseful tool to predict what can, and cannot, possibly formunder the point conditions representative of actual fieldparameters. Due to these uncertainties, the results should beused as a guide to better understand the corrosionmechanisms inside the pipeline.

SYSTEM DEFINITION

Prior to any thermodynamic analysis, it is important to definethe terms of the calculations. Table 2 shows sales gascompositions and measured dew points as obtained from twospot analyses each4. Table 3 shows impurity levels andproperties of sales gas4. These levels were used to set theconditions for the calculations outlined in the followingsections of this article.

Assumption for the Analysis

There are two main assumptions made throughout thisanalysis.

• CH4 and N2 were removed from the calculations andreplaced with Argon (Ar) so as not to impact on thereaction equilibrium.

• The sales gas would behave as an ideal gas (ideal gasbehavior). This is validated by the dew pointcalculations, Eqn. 1, that match exactly when the idealgas model is used, but are not comparable when a realgas model is used.

One problem with thermodynamic calculations is thatreactions that normally do not occur due to kinetic barrierscannot be prevented in the calculations without the removalof some species from the calculation. An important exampleof this is the reaction between oxygen and methane:

2O2 + CH4 = CO2 + 2H2O (1) Table 3. Composition and properties of sales gas used in the current work

Composition and LevelsProperties of Sales Gas

H2S 2.0 ppm and 6.0 ppmCO2 0.1, 0.5 and 1.6 mol%O2 0.01, 0.02 and 0.05 mol%

Moisture (H2O) in gas 0.12 mg/L gas and 0.55 mg/L gasAmbient Temperature 15 °C to 30 °C

Pipeline Pressure 720 psi and 900 psi

Table 2. Sales gas hydrocarbon composition and dew points

CH4 C2H6 C3H8 iC4 nC4 iC5 nC5 C6 N2 Dew Calculated(Iso- (normal (Iso- (normal (Hexanes point water

Butane) butane) pentane) pentane) plus) °C at content130 psi

78.81 8.12 3.01 0.48 0.83 0.20 0.16 0.03 7.38 -19 0.12 mg/l85.34 7.26 0.79 0.17 0.30 0.10 0.09 0.04 5.78 0.0 0.55 mg/l

corrosion rates6, 8. This again points to the difficulty inmaking a quantitative analysis of the entire system. As ageneral rule of thumb, it has been recommended thatoperators of transmission pipelines should consider limitingmaximum oxygen concentration to 10 parts per million byvolume (ppmv) (0.001 mol%)6, 8. It is important tounderstand that O2, due to air ingression in the gas, will inreality, not be at equilibrium with the other gases in themethane stream, due to the low kinetics of methane reactingwith oxygen at the operating temperatures. Oxygen cannotexist (thermodynamically) in a reducing environment suchas sales gas – as indicated by reaction (1), since it wouldreact with methane. If oxygen were at equilibrium with themethane, the partial pressure of O2 would be undetectablein this reducing atmosphere, and CO2 and water concen-trations would increase, (H2S would remain relativelyunaffected). This means that the conditions indicated by theequilibrium gas composition (i.e., the Eh* and pH of thewater or the equilibrium CO2 in the gas phase) will notreflect the true kinetically controlled situation. Therefore,any calculations or diagrams generated based on the gasphase equilibrium must be interpreted in light of theexpected kinetics (i.e., that oxygen could remain in thesystem as a kinetically stable gas phase).

Specific reactions in black powder production that areproblematic with regards to the application of thermo-dynamics are outlined below.

The ramification of the kinetic barriers is that it is difficultto accurately predict the equilibrium aqueous phase.Although, by suppressing reactions in the calculations thatwill not occur in the pipeline, a reasonable estimate of theaqueous phase can be made. This allows for a much moreuseful analysis of the iron reaction products, since EpHdiagrams can be studied with the knowledge of the aqueousphase chemistry.

DEW POINT DETERMINATION

To demonstrate the validity of the calculations, the dew pointswere calculated for a range of conditions, Fig. 1. Theoperating temperature and pressure range were 15 ºC - 30 ºCand 720 psig - 900 psig, respectively. Dew point calculationsconsidered both that the balance of the sales gas was N2 andCH4 (CH4/N2 = 15.67) or Ar for purposes of the calculations.It was determined that pressure has the largest effect on dewpoint, more than any other variable.

Calculations were performed to determine if dew pointtemperature changes as a function of contaminant concen-trations and pipeline pressure. Figure 1 shows thecomparison between the results obtained from acommercially available software package and the dew pointcalculated using the alpha moisture system (http://www.dew-point.com/calculate.html) dew point calculator. In all cases,the results are within about 2 ºC of each other. As expected,the impurities (H2S and CO2) had no significant effect on

the dew point, while pipeline pressure and H2O significantlyaffected dew point temperature.

Point Calculations

Point calculations are thermodynamic calculations done toattempt to simulate the conditions in the precipitated water inthe pipeline. They are most effectively used to identifyreasonable ranges of pH or redox for EpH diagrams or tohelp better understand reaction mechanisms. All calculationsare based on one liter of gas and are in units of moles. Theoutput from the thermodynamic model gives the equilibriumgas phase and the aqueous condensed phase.

By changing the values of CO2, H2S and O2, a range ofvalues for pH, Eh, and aqueous species concentrations can beobtained. The concentration of aqueous species is importantso that the EpH diagrams can be set to the correct values.Oxygen can be used in these calculations because methaneand nitrogen have been replaced with Ar. This conditionrepresents a sort of transient condition where O2 has ingressedinto the pipeline, but does not react with methane due tokinetic constraints.

In this way, a grid was set up to see the impact of changinggas conditions on the Eh and pH of the solution. The resultsof this (low and high CO2 content) are shown in Tables 4 and5. The water concentration was selected at a maximum valueof 0.55 mg/l.

These point calculations indicate that CO2 will buffer theaqueous solution to a pH of about 4 – typical of carbonatesolutions. The addition of H2S in a reducing environment haslittle impact on the pH. The presence of oxygen also naturallydrives up the Eh value, so there is the potential for localizedincreases of Eh along the pipeline due to oxygen ingress.


Fig. 1. Calculated dew points as a function of pipeline pressure and two differentsoftware packages assuming ideal gas with Ar substituting N2 and CH4.

Water Concentration (mg/L)

0.0 0.1 0.2 0.3 0.4 0.5 0.6

Dew

Po

int

(ºC

)

0

5

10

15

20

25

30

35

Fact 900 psiFact 720 psiInternet 900 psiInternet 720 psi

* Eh refers to the redox potential “E” of the solution,usually the Y axis on the EpH diagram (sometimescalled an Eh-pH diagram).


of reactants. The fact that FeCO3 is found preferentially at highlevels of CO2/H2S indicates that the kinetic reaction for S is lessthan that for CO2 (perhaps due to a passivating film that occurswith sulfur) or due, as mentioned above, to exhaustion of S at thereaction site due to the slow dissolution of more H2S into thewater (slow replenishment of S in the water).

As with CO2, the calculations involving S as described arealso kinetically controlled. The prediction of the formation ofSO4

2- from thermodynamics is not what occurs in the field.Reactions of oxygen and H2S appear to be kinetically slow,and the preferential reaction is as per reaction (2).

2 H2S + O2 = 2 H2O + 2S (2)

EPH DIAGRAMS

EpH diagrams can be used to identify regions of pH and E (redoxpotential, or the oxidizing or reducing environment of thesolution). These diagrams are often presented in a series withvarying conditions of activity of one of the species. This is because,while EpH diagrams can be constructed for metals in water, whena nonmetallic element is introduced (in this case carbon or sulfur),another degree of uncertainty is added to the system. This has tobe removed by setting the activity level or partial pressure of acompound containing that nonmetallic element. Providing a seriesof diagrams with no reference to the actual system has little valuein understanding the mechanism of a reaction. For this reason, thepoint calculations that were performed in this work are useful inhelping to determine reasonable concentrations of aqueous speciesfor carbon and sulfur. As a baseline, the EpH diagram for waterwas constructed, Fig. 2. FeOOH, the data for which was enteredinto the commercial software package8, was not shown to appear.Conditions for its formation are not at present clear, but it can beassumed that it forms in the presence of oxygen via reaction (3),

2Fe + H2O(l) + 3/2 O2 = 2 FeOOH (3)

The fact that there are no pH conditions that would beabove about 5 is in line with the work by Sridhar et al.5,which used a range of conditions for their test, with CO2 at10 psi and all conditions (except the one loaded with NaOH)showing a pH around 5.

The results mentioned above reinforce the difficulties ofstudying the problem in isolation from its surroundings. Theserelatively highly acidic pH conditions are not encountered inthe pipeline. The presence of iron in the system has a dramaticeffect on the actual chemistry. The pH of the system isnormally found to be between 5 and 6.5, due to the reactionof CO2 with iron. When iron is introduced into the cal -culation, FeCO3 precipitates, the pH increases to 5, andFeOH+ is found in the aqueous solution. This is much more inline with the actual field findings. The formation of Fe3O4 isthermodynamically possible but depends on the availability ofiron to the system (ratio of iron to gas phase). This could helpto explain the range of compounds found in the pipeline.

The progression of product formation can be studied bylooking at the calculated reaction products as iron is introducedinto the system. In the presence of any Fe (given an oxygen freesystem), FeS2 is the first iron compound to form (at around pH~4). FeCO3 forms next if the available sulfur is exhausted, whichwill increase the pH to above 5. The relative rates of thesereactions are not known and are affected by the relative concen-trations of the gases. It has been stated6 that when CO2 and H2Sare both present in condensed moisture, the corrosion productthat forms is a function of the partial pressure of both acid gasesand temperature. Several investigators have suggested differentCO2/H2S ratios, such as 200 and 500, which represent the changefrom predominately FeCO3 to FeS6. It should be noted that thepreference for CO2 forming carbonate over H2S forming FeS(both reactants in aqueous form) is a kinetic phenomenon, andnot based on thermodynamics. Thermodynamically, iron willpreferentially react with S over CO2 at virtually any concentration

Table 4. Impact of changing gas concentrations on the aqueous phase (CO2 = 0.1 mol%, H2O = 0.55 mg/l, P = 720 psi, T = 15 °C)

O2

Concentration H2S Concentration (ppm)(mol%) 0 2 6

Eh (V) pH Eh (V) pH Eh (V) pH0 0.562 4.546 -0.003 4.283 -0.003 4.244

0.01 0.944 4.546 1.216 -0.205 1.237 -0.5580.05 0.954 4.546 1.227 -0.205 1.24 -0.558

Table 5. Impact of changing gas concentrations on the aqueous phase (CO2 = 1.6 mol%, H2O = 0.55 mg/l, P = 720 psi, T = 15 °C)

O2

Concentration H2S Concentration (ppm)(mol%) 0 2 6

Eh (V) pH Eh (V) pH Eh (V) pH0 0.596 3.944 0.024 3.893 0.022 3.882

0.01 0.979 3.944 1.231 -0.204 1.252 -0.5580.05 0.989 3.944 1.227 -0.204 1.248 -0.558

must be a species selected that has a fixed concentration. Thiscan either be a gas (i.e., CO2) or an aqueous species (i.e.,HCO3

-). HCO3- was selected, and a representative value was

taken from the point calculations done in the last section. Note that the carbonate phase, FeCO3, is covered by the

aqueous FeOH+ and Fe2+ fields. This only indicates the ionicconcentration in the system, since the diagram is set to the typical10-6 concentration for the sum of ionic species (if the total of allionic species is at least 10-6, the predominant ionic species will beshown on the plot). To see the solid phases, the ionic species canbe suppressed in the output, Fig. 4. This plot, without aqueousspecies shown, clearly demonstrates that FeCO3 is the significantphase in the E and pH range that is of interest. This supports thepoint calculations showing that FeOH+ is present with CO2 andhas an influence on the pH of the system.

Often, EpH diagrams are shown with the aqueous phaseboundaries as dotted lines over the top of the solid phases.The concentration of aqueous species over a phase field givesan indication of the drive for corrosion, since corrosion willoccur with greater intensity if the dissolved Fe ions are able tobuild to a high concentration before equilibrium is reached.For ease of discussion in this section, the concentration ofaqueous species will be set at 0.001 so that the solid phasefields may be seen with the aqueous species.

It is evident that Fe3O4 forms at pH values above about6.5, but that the phase field overlaps the FeCO3 for a givenpH, depending on the Eh of the system. This could explainwhy both FeCO3 and Fe3O4 are found in the black powder,since a pH of 6.5 or greater is found in laboratory tests atSaudi Aramco, and it is reasonable that the Eh could changedepending on the availability of oxygen.Influence of H2S on the system:

Influence of H2S on the System

The effect of H2S on the pipeline is highly dependent on theatmosphere in the pipeline and kinetics – as mentioned,


or through conversion of reaction products via reactions (4) and (5):

4FeS + 2H2O + 3O2 = 4FeOOH + 4S (4)

Fe3O4 + 3/2 H2O + 1/4 O2 = 3 FeOOH (although likely kinetically limited) (5)

This diagram is at 15 ºC, although the effect of temperatureis negligible over the range that is experienced by thepipelines. The region of interest is between the two dashedlines. These lines indicate the region where water is stable. Itis clear that with only pure water and a basic pH, it ispossible to form Fe3O4, as shown by the region in Fig. 2. Theprogression is from elemental Fe, to FeO (or Fe(OH)2 asshown) to Fe3O4 and finally to Fe2O3 – the most oxidized ironoxide. If the aqueous species were to be removed from thediagram, it would show each phase field layered on top ofeach other as the E(V) increases (becomes more oxidizing).

Influence of CO2 on the System

With the addition of CO2, the EpH diagram changes to thatshown in Fig. 3 for a system with low CO2 in the gas phase(0.1 mol%). Here, because C is added to the system, there

Fig. 2. EpH diagram for Fe in water.

0 2 4 6 8 10 12 14

E(V

)

-1 .2

-1 .0

-0 .8

-0 .6

-0 .4

-0 .2

0.0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

1.6

1.8

Fe (s)

Fe 2+

Fe (O H ) 2(s)

FeO H+

T = 15 oCa (ions) = 10-6

Fe 3+

Fe 2O 3(s)

Fe 3O 4(s)

Fig. 3. EpH diagram for Fe-C in water for low CO2 in gas phase.

p H0 2 4 6 8 1 0 1 2 1 4

E(V

)

-1 .2

-1 .0

-0 .8

-0 .6

-0 .4

-0 .2

0 .0

0 .2

0 .4

0 .6

0 .8

1 .0

1 .2

1 .4

1 .6

1 .8

F e (s )

F e 2 +

F e O H+

T = 1 5 oCa ( io n s ) = 1 0 -6

F e 3 +

F e 2 O 3 (s )

F e 3 O 4 (s )

Fig. 4. EpH diagram for Fe-C in water for low CO2 in gas phase (no ionicspecies shown).

pH

0 2 4 6 8 10 12 14

E(V

)

-1.2

-1.0

-0.8

-0.6

-0.4

-0.2

0.0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

1.6

1.8

Fe (s)

T = 15 oC[HCO 3

-] = 10-5

no ions shown

Fe 2O3(s)

Fe 3O4(s)

FeCO 3(s)


formed in the pipelines at varying conditions (thermodynamicand kinetic controlled regions) a complex task. Even so,thermodynamics can be a useful tool to predict what can, andcannot, possibly form using well-defined conditions (the pointconditions provided by Saudi Aramco).

ACKNOWLEDGMENTS

The authors wish to thank Saudi Aramco management fortheir support and permission to present the informationcontained in this article.

REFERENCES

1. Sherik, A.M., Zaidi, S.R., Tuzan, E.V. and Perez, J.: “BlackPowder in Gas Transmission Systems,” paper 8415,presented at the NACE Corrosion Conference, NewOrleans, Louisiana, March 16-20, 2008.

2. Baldwin, R.M.: “Black Powder in the Gas Industry-Sources, Characteristics and Treatment,” GMRC, ReportNo. TA97-4, May 1998.

3. Sherik, A.M.: “Black Powder in Sales Gas TransmissionPipelines,” Saudi Aramco Journal of Technology, Fall2007, pp. 2-10.

4. Sherik, A.M.: “Effects of Simulated Pipeline Processes onBlack Powder Formation in Sales Gas Pipelines,” ReportNo. DR-002/05-COR, April 2007.

5. Sridhar, N., Dunn, D.S., Anderko, A.M., Lencka, M.M.and Schutt, H.U.: “Effects of Water and Gas Compositionson the Internal Corrosion of Gas Pipelines – Modeling andExperimental Studies,” Corrosion, Vol. 57, No. 3, 2001,pp. 221-235.

6. Kermani, B., Martin, J. and Esaklul, K.: “Materials DesignStrategy: Effects of H2S/CO2 Corrosion on Materials Selec -tion,” paper 06121, presented at the NACE CorrosionConference, San Diego, California, March 12-16, 2006.

7. Lyle, F.F.: “Carbon Dioxide/Hydrogen Sulfide Corrosionunder Wet Low-Flow Gas Pipeline Conditions in thePresence of Bicarbonate, Chloride and Oxygen,” PRCIFinal Report PR-15-9313.

8. Majzlan, J., Grevel, K.D. and Navrotsky, A.:“Thermodynamics of Fe Oxides: Part II. Enthalpies ofFormation and Relative Stability of Goethite (γFeOOH),lepidocrocite (αFeOOH), and Maghemite (γFe2O3),”American Mineralogist, Vol. 88, 2003, pp. 855-859.

oxygen does not react kinetically with H2S to create sulfates.This means that EpH diagrams can vary widely as to thefields of stability depending on the situation in the system.Figure 5 shows a simple EpH diagram using the pH2S as thebasis for the calculation yields. This shows Fe3O4 in betweenFeS and FeS2. The Fe3O4 field is very narrow (it is onlyvisible as a thicker line) but at lower H2S concentrations it ismore predominate. This demonstrates that there is thelikelihood for FeS and FeS2 to form depending on the redoxpotential. Since oxygen ingression will affect the redoxpotential significantly, and oxygen ingression is a relativelynonuniform event (sometimes minor, sometimes major), it islikely that both FeS and FeS2 will be found in a range ofconcentrations with one another.

Both the case of CO2 and H2S demonstrate why a variety ofsolid material is found in black powder. Oxygen ingress canwidely vary the Eh of the system and favor the formation of onecompound over another. The nature of the ingress – ranging inconcentration and location – leads to this nonuniform residueand complicates the overall analysis of its formation.

CONCLUSIONS

It is clear from this analysis that internal corrosion of pipelinesand black powder formation in sales gas pipelines is a complexprocess that is not thermodynamically controlled – however,thermodynamics can assist with our understanding of theunderlying chemical processes. The fact that there is a widerange of products (iron oxides, iron carbonates and elementalsulfur) sampled from the pipelines indicates that this is not ahomogeneous process that may not be controlled by thermo-dynamics. These products are mainly due to: (1) intermittentingress of oxygen resulting from process upsets, and (2) thecyclical wet-dry conditions resulting from process upsets andseasonal temperature changes. This makes the attempt tocorrelate the iron phases obtained at well-defined thermo -dynamic conditions to the composition of the black powder

Fig. 5. EpH diagram for Fe-S in water for pH2S = 10-8.

pH

0 2 4 6 8 10 12 14

E(V

)

-1.2

-1.0

-0.8

-0.6

-0.4

-0.2

0.0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

1.6

1.8

Fe (s)

Fe 2+

FeS (s)

FeOH+

T = 15 oCpH2S = 10 -8

a(ions) = 10-6

Fe 3O4(s)

FeS 2(s)


BIOGRAPHIES

Dr. Abdelmounam M. Sherik joinedSaudi Aramco in 2004 and is currentlyworking for Saudi Aramco’s Researchand Development Center (R&DC).Prior to joining Saudi Aramco, he heldseveral research and engineeringpositions in Canada. Abdelmounam

has over 20 years of professional experience in the areas ofmaterials and corrosion. He received his B.S. degree inMaterials Science and Engineering from Tripoli University,Tripoli, Libya and his M.S. and Ph.D. degrees in Materialsand Metallurgical Engineering from Queen’s University,Kingston, Ontario, Canada.

Abdelmounam has authored or co-authored more than50 publications in corrosion of sales gas pipelines and nano-structured coatings. He is an active member of the NationalAssociation of Corrosion Engineers (NACE), where he isthe Chair of the 2010 Corrosion in Gas TreatingSymposium and also the Chair of the Black Powder in GasPipelines Technology Exchange Group.

Dr. Boyd R. Davis has worked as aconsultant since 1997 in the area ofcomputational thermochemistry andprocess development, and is Presidentof Kingston Process Metallurgy Inc.The company, with 12 employees,focuses on lab-scale chemical process

development for the metallurgical industry – mainly indeveloping and advancing novel processes and under -standing reaction mechanisms. He also has a secondcompany called Kingston Metals & Materials, whichproduces high purity copper for the semi-conductorindustry. Aside from his companies’ projects, Boydmaintains an active academic research program. Boydvolunteers his time to supervise graduate and undergraduatestudent theses and to teach in a first-year design course. Hehas authored over 20 technical papers and has eight patentsand patent applications. Boyd is Programming Chair of theExtractive and Processing Division of The Metals, Minerals,and Materials Society and is active with the MetallurgicalSociety of CIM where he was awarded the Past Presidents'Memorial Medal in 2001 for service.

In 1988, Boyd received his B.S. degree in EngineeringChemistry and in 1994 he received his M.S. and Ph.D.degrees in Metallurgical Engineering, all from Queen'sUniversity, Kingston, Ontario, Canada.

ABSTRACT

Water control is the key to prolonging well life for economicaland efficient oil recovery. When water reaches certain levels,oil production profitability decreases dramatically and evengoes to negative. One feasible option in this case is a riglesswater shut-off (WSO) treatment, which involves an intensiveprocess, starting from candidate selection and finishing withpost-treatment well performance analysis. This kind ofoperation is more challenging for horizontal wells with openhole completion. Well A, a horizontal open hole producerwith 2,440 ft of reservoir contact, was drilled and completedin November 2000. The last well production profile wasdetermined by a Flow Scan Image (FSI) log, which showed51% of water cut; the entry of most of the water was fromthe toe of the horizontal section. Based on economical andtechnical feasibility, fiber optic telemetry enabled coiled tubing(CT) was selected as an accurate and effective way to isolatethe water producing interval, reduce water cut and enhanceoil production.

The advanced and intelligent CT enables real timedownhole measurements via a fiber optic telemetry system.The system consists of dynamic interpretation software, fiberoptic cable, and bottom-hole sensors, which provides surfacereadouts of the Casing Collar Locator (CCL) readings, a

Distributed Temperature Survey (DTS), temp erature, andinternal and external CT pressure measurements. Permanentzonal isolation, utilizing an inflatable packer with a cementplug above the packer, was successfully performed using theCT-conveyed fiber optic system. The availability of CCL,temperature and differential pressure readings enabled precisedepth control, proper packer inflation and optimization of thecement design.

This article highlights the application of a CT equippedwith fiber optic advanced technology on a rigless WSO job.This article also discusses the WSO job design and executionchallenges.

INTRODUCTION

Drilling horizontal wells has become the norm in many SaudiAramco fields. As horizontal wells mature, the oil rate is reduceddue to increasing water production, which dictates the need toperform water shut-off (WSO) jobs to sustain oil production.

Performing a WSO on a horizontal well is considered achallenging task in the Ghawar field, the largest field in theworld. Production profiles are run to determine the waterproducing intervals and to come up with the best methodsto shut-off the watered out intervals. Inflatable packersprovide a means of plugging off a well without the necessity


Successful Utilization of Fiber Optic TelemetryEnabled Coiled Tubing for Water Shut-off ona Horizontal Oil Well in Ghawar Field

Authors: Ahmed K. Al-Zain, Jorge E. Duarte, Surajit Haldar, Saad M. Driweesh, Ahmed A. Al-Jandal, Faleh M. Al-Shammeri, Vsevolod Bugrov and Tashfeen Sarfraz

Fig. 1. Fiber optics in a carrier (FOC).

of pulling out its production tubing. Due to the minimumrestriction in the tubing, the selection of an inflatable packeris always limited1, 2.

Traditionally, the WSO on a horizontal well requires coiledtubing (CT) intervention to isolate the water producing zone,using a through-tubing inflatable packer, and a cement cap with aspacer to reduce the cement slumping effect. When setting thepacker, surface data has been deceptive. What actually happensdownhole remains unknown. The uncertain results when bottom-hole pressure (BHP) is estimated from surface pressure and depthsmeasured from the CT surface mechanical counters are somecommon problems. The recent invention of optical fiber enabledCT allows us to mitigate these problems to a great extent3, 4.

DESCRIPTION OF FIBER OPTIC ENABLED COILEDTUBING

Optical fibers are widely used in communication and otherapplications. Fibers are used instead of metal wires becausesignals travel along them with less loss, and they are immuneto electromagnetic interference. A fiber optic cable, which actsas a medium between an engineered downhole tool and asurface acquisition system, is injected into a CT reel. The fiberoptic cable is enclosed and protected in a flexible yet verydurable carrier, before its injection into the CT, Fig. 1.

The fiber optic carrier (FOC) has an 1.8 mm (0.071”) outsidediameter (OD), making it non-intrusion to the CT internaldiameter. It is very lightweight, equivalent to 1/20th of the weightof an electric cable. The material itself can withstand corrosive andharsh bottom-hole conditions and temperatures up to 300 ºF5.

Downhole and Surface Equipment

The system provides a real-time bottom-hole measurement forCT applications. It consists of a bottom-hole assembly (BHA),CT string with an internal fiber optic cable, and surface unit formonitoring and execution. This CT system has drop ballcapability. Figure 2 shows the BHA with the following threeelements that relate to CT fiber optic technology:

• CT head: This section includes an internal dimpleconnector.

• Electronic Package: This houses the downholecommunications module, the battery to power the systemand the downhole transducers for measuring bottom-holetemperature (BHT) and BHP, internal and external.

• Casing Collar Locator (CCL): The CCL has the abilityto sense casing collars for depth correlation.

Inside the Control Cabin, a surface acquisition unit withspecialized software is utilized to acquire, display, monitorand record job parameters and assist in executing the joboperations; consequently, enhancing the performance of thejob using the real time data. The surface acquisition unit isalso used to send commands to the tools, such as to changethe sensitivity of the CCL during the job.

WATER SHUT-OFF CASE HISTORY

Well A was drilled as a slanted open hole horizontal producerin 2000. The well is completed with a 6.125” horizontalsection from 7,550 ft to a total depth (TD) of 9,900 ft. Theproduction test obtained before performing the WSO jobshowed 7,200 barrels per day (BPD) total liquid with 51%water cut. A production profile indicated most waterproduction was from 9,650 ft and below. Figure 3 shows thewell production profile and well trajectory.


Fig. 2. Schematic of CT BHA.

Fig. 3. Well production profile and trajectory.


guide per the completion report was at 7,579 ft; however,the CCL detected it at 7,586 ft, with a difference of 7 ft.Accordingly, the depth was adjusted to match the referencedCCL log and completion report. Following depthcorrelation, the CT was run in hole (RIH) to the targetdepth and the CT was flagged.

In addition to depth correlation and drifting the well, thereal-time CT weight indicator graph, Fig. 5, was utilized toevaluate the actual friction coefficients of the well. Thisallowed operators to determine whether sufficient weightcould be set on the packer after inflation to ensure that thepacker was properly set before the CT lockup. The actualweights experienced during this run were used to re-evaluatethe simulated tubing forces and determine the actualcompressive load available at 9,360 ft (packer depth).According to the analysis of CT forces, a compressive loadof 1,500 lb was available prior to CT lockup. Thiscompressive load was sufficient to test the anchoring forceof the packer. On surface, this load corresponded to a lossof 5,500 lb.

Main Job Execution – Setting Inflatable Packer

A through-tubing inflatable packer (element OD 2½”) wasused. The objective of the second run was to RIH to 9,360 ftand set the inflatable packer. The setting depth was 9,360 ftand setting the packer at the proper depth was veryimportant. The CCL tool was used in this run for depthcontrol. The BHP was evaluated constantly while running inhole to avoid premature inflation of the packer.

Another important parameter was the differential pressureat which the packer was set in place. First, the tool settingswere adjusted based on actual BHP and BHT readings, whichwere obtained during the drift run. Second, the correctdifferential pressure measured by the fiber optic CT ensuredthat the inflation process was as per the design and in acontrolled manner. Figure 6 depicts the execution plot whileinflating the packer.

The main highlights of the execution process for setting thepacker at the desired depth were as follows:

1. The CT was run to a depth of 9,360 ft. The CT wasinitially run 100 ft below the desired depth and then pulled

DISCUSSION OF JOB OPERATIONS

The plan was to plug back the well to 9,200 ft to ensureproper WSO. A 2½” open hole through-tubing inflatablepacker was set at a depth of 9,360 ft and capped with 160 ftof cement on top of the packer to anchor it. The operationswere performed rigless using the fiber optic CT. Below is abrief discussion of the operations.

Depth Correlation/Dummy Run

The objective of this run was to ensure wellbore clearance (forpacker setting) and CT accessibility to the target depth. Forthis purpose, the BHA of the CT was run with a 2½” ODtool, which is the maximum OD of the inflatable packerelement. Depths were correlated using the CCL readingsprovided by the fiber optic CT against a reference log and acompletion report. Another purpose for this run was to verifysimulation results of the CT tubing forces. This enabled theoperator to re-evaluate the friction coefficient of the wellbore,and determine if a sufficient slack-off weight would beavailable at the packer setting depth.

The log in Fig. 4 represents the CCL signal at the tubingre-entry guide. The re-entry guide was used for depthcorrelation as the casing shoe is behind the tubing. The

Fig. 4. Unadjusted fiber optic enabled CT CCL log. Fig. 5. Simulated vs. actual pickup and slack off of CT.

out to the target depth to keep the CT in tension; CCLwas used to correlate depths to the re-entry tubing guide.

2. After dropping a ball down the CT, the differentialpressure at the packer was monitored to track the ballto its seal. The pressure indicated positively that the ballwas seated. The differential pressure then was raised in200 - 300 pounds per square inch (psi) increments; oncethe pressure was at 700 psi, the packer was allowed toinflate in its own. While waiting for stabilization for 10- 15 minutes, the BHT heated the packer andconsequently the pressure inside of the packer continuedincreasing, Fig. 7. Realizing this behavior, controllingpacker inflation was very important. Otherwise, thepacker could be inflated improperly. Once the pressureand temperature were stabilized, the pumping wasresumed carefully at points X and Y to complete theinflation of the packer.

3. Note: The downhole pressure and temperature data wasalso passed to the cement laboratory to verify theproper cement recipe.

4. To ensure that the packer was set in place, 2,000 lbs ofweight was slacked down on the packer to ensure it wasanchored into the wellbore. The CT did not move, andthis indicated that the packer was set in place.

5. The next step was to increase the differential pressure todisconnect the packer from the CT. The disconnectionoccurred at 1,260 psi differential pressure. Thedifferential pressure of 1,260 psi for disconnection, asactually measured downhole, was in close agreement tothe designed differential pressure of 1,200 psi (less than+/- 10% manufacturing tolerance for the brass shearpins).

6. Once the pins were sheared, the circulation portsopened allowing the circulation pressure as well as thedifferential pressure to drop, indicating that the packerhad been disconnected from the tool string.

The CT was then pulled out of hole to change the BHA forthe cement job. By this time, laboratory tests had beenperformed and the cement recipe had been adjusted to fit theactual bottom-hole condition.

Cement Job

The CT was run to the top of the packer and the cement wasspotted as follows:

• Spacer (5 bbl each) was pumped ahead and behind thecement to avoid cement contamination while it passedthrough the CT string and also to clean up the wellbore,where the cement was placed.

• Cement (5.5 bbl) was pumped to cover 160 ft in theopen hole.

After the cement was spotted, the well was shut-in for 24hours. This was to allow the cement to develop sufficientcompressive strength. Following this, the CT was RIH toconfirm the top of the cement. The top of the cement wasfound at 9,166 ft (5,000 lb slack-down weight), which wasonly 34 ft above the calculated desired depth of 9,200 ft.

BENEFITS OF USING FIBER OPTIC ENABLED CT

Fiber optic technology was utilized to ensure good servicequality of depth control, packer setting and inflation process.The element design was adjusted as per actual BHP and BHT.


Fig. 6. Fiber optic enabled CT execution plot while inflating the packer.

Fig. 7. Pressure and temperature behavior while setting the packer.


ACKNOWLEDGMENTS

The authors wish to thank Saudi Aramco and Schlumbergermanagement for their support and permission to present theinformation contained in this article. The authors would alsolike to acknowledge the efforts and contributions of Rifat Saidof Saudi Aramco, and Wassim Kharrat and Adrian Weiss ofSchlumberger.

SI METRIC CONVERSION FACTORS

bbl × 1.5897 E-01 = m3in × 2.540 E-02 = mft × 3.048 E-01= mpsi × 6.894757 E+00 = kPa

REFERENCES

1. Al-Dhafeeri, A.M., Nasr-El-Din, H.A. and Al-Harith,A.M.: “Evaluation of Rigless Water Shut-off Treatments tobe Used in Arab-C Carbonate Reservoir in Saudi Arabia,”SPE paper 114331, presented at the SPE CanadianInternational Petroleum Conference, Calgary, Alberta,Canada, June 2008.

2. Rangel, P.D., Sorman, I., Blount, C.G. and Woods, N.:“Fiber Optic Enabled Coiled Tubing Operations onAlaska’s North Slope,” SPE paper 106567, presented at theSPE International Coiled Tubing Operators AssociationConference, The Woodlands, Texas, March 2007.

3. Al-Umra, M.I., Saudi, M.M. and Al-Tameimi, Y.M.:“Inflatable Enables Successful Water Shut-off in HighAngle Wellbores in Ghawar Field,” SPE paper 93261,presented at the SPE Middle East Oil & Gas Show andConference (MEOS), Bahrain, March 2005.

4. Dashash, A.A., Al-Arnaout, I., Al-Driweesh, S.M., Al-Sarakbi, S.A. and Al-Shaharani, K.: “Horizontal WaterShut-off for Better Production Optimization and ReservoirSweep Efficiency,” SPE paper 117066, presented at the SPESaudi Arabia Section Technical Symposium and Exhibition,Dhahran, Saudi Arabia, March 2008.

5. Graeme, R., Yusof, M.B., Ghani, J., Mokhtar, S. andMunro, J.: “Improved Method for UnderbalancedPerforating with Coiled Tubing in the South China Sea,”SPE paper 113698, presented at the SPE InternationalCoiled Tubing Operators Association Conference, TheWoodlands, Texas, April 2008.

The real time data and CT weight gave a strong indication thatthe packer was set in its place. The BHP was monitored to avoidpre-mature packer inflation. The cement recipe was formulatedbased on measured downhole temperature and pressure.

The most beneficial use of differential pressure was whilesetting the packer; the actual differential pressure was relativelyclose to that of the design. The CCL was utilized to eliminatethe error of CT mechanical depth measurement. This in turnhelped ensure the depths were accurate and the operation wasperformed in the exact same intervals per design. Having theability to know accurately the bottom-hole parameters helpedto make better decisions.

POST JOB WELL PERFORMANCE

The well was put back on production and the initial testresults indicated these reductions, Table 1.

CONCLUSIONS

1. Reliable and real time data obtained from fiber opticenabled CT is a real breakthrough in most CT applications(WSOs, stimulations, perforations, etc.). Fiber optictelemetry enabled CT provides real time data for criticaloperational parameters. The data includes CCL, BHT, BHPand differential pressure.

2. This technology is a viable method to communicate directlyand continuously downhole with wellbore, reservoir ortools conveyed via CT. A direct communication withdownhole conditions avoids relying on calculatedparameters from surface readings, which most of the time,are far from real downhole conditions. This will helpoperators to come up with the right decisions on-site.

3. CCL is a viable and efficient option for depth control asdemonstrated in this article.

4. Real time pressure and temperature data enabled preciseplacement and proper inflation of the inflatable packer toshut-off water production as shown from the WSO casehistory. The BHP and BHT data was also used to validatethe cement recipe.

5. Based on this successful experience, fiber optic enabled CTwas used on six other WSO jobs. The technology is beingpilot tested to optimize acid stimulation jobs on longhorizontal and extended reach wells.

Table 1. Post treatment production analysis showed a reduction in water cut by79% and a gain in oil production of 112%

Oil rate, Water, WC% Choke MBD MBD Setting, in

Before WSO 3.1 2.9 47.8 50After WSO 6.6 0.6 8.4 50Total Gain= Reduction= Reduction=

3.5 MBD 2.3 MBD 39.4%


Ahmed A. Al-Jandal is a PetroleumEngineering specialist in the SouthernArea Production EngineeringDepartment (SAPED). He earned hisB.S. degree in Petroleum Engineeringfrom King Fahd University ofPetroleum and Minerals (KFUPM),

Dhahran, Saudi Arabia in 1986. Ahmed has been withSaudi Aramco for the past 25 years, where his experienceincludes working with production engineering on the oiland water injection wells in SAPED, and leading thespecialist unit for the Oil and Water Well Treatment/Stimulation Unit for the Southern Area Oil Operation(SAOO) fields. Currently, he is the Production EngineeringSupervisor for the north Ghawar water injection wells.

Faleh M. Al-Shammeri joined SaudiAramco in 2003 as a ProductionEngineer working with the SouthernArea Oil Operation (SAOO)organization. He has 6 years experienceworking in several fields, includingHawiyah, Shedgum and ‘Ain Dar.

During this time, Faleh handled various projects, such as thelanding base, inactive wells, power saving and the highshut-in wellhead pressure wells (HIPS) project, in additionto his routine production operation activities.

Faleh received his B.S. degree in Petroleum Engineeringfrom King Saud University, Riyadh, Saudi Arabia in 2001.

Vsevolod Bugrov received his M.S.degree in Petroleum Engineering in2003 from the Russian State universityof Oil and Gas, Moscow, Russia. Aftergraduation he started his career withSchlumberger as a Coiled TubingEngineer.

He has 6 years of experience in well intervention andstimulation services, including various applications ofcoiled tubing in Arctic and desert conditions. Currently, heworks in ‘Udhailiyah providing technical support for theSouthern Area Production Engineering Department(SAPED) Coiled Tubing operations.

Tashfeen Sarfraz is an ElectronicsEngineer working in Schlumberger’sCoiled Tubing Services, ‘Udhailiyah,Saudi Arabia. He is responsible for thetechnical design and execution of newtechnology operations, and was amember of the team that executed the

first Water Shut-off campaign for Saudi Aramco in 2007.Tashfeen is a member of the Society of Petroleum Engineers(SPE) and has published several technical papers andarticles. He has 5 years of experience, mainly in wellintervention and stimulation services.

In 2003, Tashfeen received his B.S. degree in ElectronicsEngineering from Ghulam Ishaq Khan University, Topi,Pakistan.

BIOGRAPHIES

Ahmed K. Al-Zain currently works asa Production Engineering Specialist inwell treatments in the Southern AreaProduction Engineering Department(SAPED). He received his B.S. degreein 1989 in Petroleum Engineering fromTulsa University, Tulsa, OK. After his

graduation, Ahmed joined Saudi Aramco as a ProductionEngineer and worked in various sandstone and carbonatemajor fields in the Southern area. He now has over 20years of experience, mainly in production engineering aswell as in reservoir and drilling engineering. Ahmed haspublished several technical papers on various topics, suchas acid stimulation, scale inhibition, water compatibility,coiled tubing applications and automated well dataacquisitions.

Jorge E. Duarte is a ProductionEngineer working in the GasProduction Engineering Division. Hehas 13 years of oil field experience.In 1996, Jorge received his B.S.degree in Petroleum Engineeringfrom the Universidad America,

Bogota, Colombia.

Surajit Haldar received both his B.S.degree in Chemical Engineering in1989 and his MBA in 2006 from theIndian Institute of Technology,Kharagpur, India. He has 20 years ofwork experience in the petroleumindustry, including 8 years in research,

development and consultancy work on well stimulation andwater shutoff technology. Currently, Surajit is working as astimulation and water shutoff champion for water and oilwells in the Southern Area Production EngineeringDepartment (SAPED).

Saad M. Al-Driweesh is a ProductionEngineering General Supervisor in theSouthern Area Production EngineeringDepartment (SAPED), where he isinvolved in gas and oil productionengineering, well completion andstimulation activities. He is mainly

interested in the field of production engineering, productionoptimization and new well completion applications.

In 1988, Saad received his B.S. degree in PetroleumEngineering from King Fahd University of Petroleum andMinerals (KFUPM), Dhahran, Saudi Arabia. He has beenworking with Saudi Aramco for the past 19 years in areasrelated to gas and oil production engineering.

ABSTRACT

Heightened concerns for cleaner air results in more stringentregulations on sulfur contents in transportation fuels that will

make desulfurization more and more important. This hasexerted strong pressure, not only on the refiners but also ongovernments and legislators. The sulfur problem is becoming

more serious in general, particularly for diesel fuels, as theregulated sulfur threshold is rising and will likely require avirtually sulfur-free liquid fuel within a few years.

Although conventional hydrodesulfurization (HDS) is stillthe preferred technology for producing the ultra clean fuels,other nonconventional methods, such as oxidative, radiative,extractive, membrane, adsorption, biodesulfurization andultrasonic approaches have also gained interest in recent yearsdue to the increased cost of revamping the existing low-

pressure hydrotreating units. Most of the alternativetechnologies have not been shown to be economically viableon a commercial scale. Oxidative desulfurization technology,

however, has progressed to the state where it is nearingcommercialization. Oxidation chemistry represents analternative route to diesel desulfurization that complements

HDS chemistry. The integration of an oxidative desulfu-rization unit with a conventional hydrotreating unit canimprove the economics of these regulation driven projects

relative to current HDS technology. Of the nonconventional approaches to reduce the sulfur

content in hydrocarbon fractions, such as adsorption,

extraction, ionic exchange, biodesuflurization and oxidation,an oxidation desulfurization (ODS) catalytic systemcomposed of sodium tungstate dihydrate (Na2WO4), aqueoushydrogen peroxide (30% H2O2) and acetic acid (CH3CO2H)has been found promising for deep removal of sulfur in

diesel. From a chemistry point of view, the sulfur compoundsare transferred to their corresponding sulfones, which can bepreferentially extracted by polar solvents. By using ODS, the

sulfur level in commercial diesel of 1,100 ppm has beenreduced to less than 39 ppm, which meets the latest stringentenvironmental legislation enforcing the production of ultra

low sulfur diesel (ULSD) (< 50 ppm). This article also coverssome discussion about the ODS process itself and a proposedreaction mechanism.

INTRODUCTION

Sulfur in transportation fuels remains a major source of SOx,which contributes to a refinery’s catalyst fouling, corrosion,air pollution and acid rain1, 2. Therefore, the threshold limitfor sulfur levels in gasoline and diesel has already beenregulated on a global level, including in Saudi Arabia, to lessthan 50 ppm of weight (ppmw) over the next few years1-4.The new environmental legislation puts both crude oilproducers and oil fraction refineries under tremendouspressure to cope with the new regulations and to push for theproduction of ultra low sulfur diesel (ULSD). One school ofthought is asking for certain revamping of the currenthydrotreatment facilities in most refineries, while the other ison the side of exploring new technologies, which mightinvolve either minor additions or even major grass rootchanges to the existing targeted facilities.

Removal of sulfur from organic sulfur compounds in liquidfuels has long been achieved by hydrodesulfurizaion (HDS) usinga Co-Mo/Al2O3 or a Ni-Mo/Al2O3 catalyst in the temperaturerange from 320 ºC to 360 ºC, and in the pressure range of 30bar to 60 bar of H2 partial pressure4-6. In this process, whichrequires the presence of excess hydrogen, the sulfur atom ishydrotreated to form mainly H2S as shown in the reaction ofethanethiol:

C2H5SH + H2 ➛ C2H6 + H2S

The H2S evolved from the HDS is a toxic gas that needsfurther treatment to form elemental sulfur, a useful non-toxicyellow powder. According to its inventor, this process is calledthe “Claus Process” in which the gaseous sulfur istransformed into elemental sulfur (S8). Solvent extractionutilizing a solution of diethanolamine (DEA) dissolved inwater is applied to separate the hydrogen sulfide (H2S) gasfrom the process stream. In this process, the H2S gas istrapped or dissolved in the DEA by bubbling a hydrocarbongas stream containing H2S through the DEA solution. Ingeneral, conversion of the concentrated H2S gas into sulfuroccurs in two stages:

1) Combustion of part of the H2S stream in a furnace, producingsulfur dioxide (SO2), water (H2O) and elemental sulfur (S):

2H2S + 2O2 ➛ SO2 + S + 2H2O


Nonconventional Catalytic Process for UltimateRemoval of Organic Sulfur-ContainingCompounds in Hydrocarbon Fractions

Authors: Dr. Farhan M. Al-Shahrani, Dr. Tiacun Xiao, Dr. Abdennour Bourane, Dr. Omer R. Koseoglu and Prof. Malcolm L.H. Green

2) Reaction of the remainder of the H2S with thecombustion products in the presence of a catalyst. The H2Sreacts with the SO2 to form sulfur:

2H2S + SO2 ➛ 3S + 2H2O

As the reaction products are cooled, the sulfur drops out ofthe reaction vessel in a molten state, which can be stored.

Sulfur-containing compounds that are typically present inhydrocarbonaceous fuels include aliphatic molecules, such assulfides, disulfides and mercaptans, as well as aromaticmolecules, such as thiophene, benzothiophene (BT),dibenzothiophene (DBT) and alkyl derivatives such as 4,6-dimethyl-dibenzothiophene (DMDBT). Those latter moleculeshave a higher boiling point than the aliphatic ones and areconsequently more abundant in higher boiling fractions.Conventional HDS technology can desulfurize aliphatic andacyclic sulfur-containing organic compounds on an industrialscale, as is the case in most refineries in the world. AromaticDBT, and especially 4,6-alkyl-substituted DBTs, are difficult toconvert to H2S due to the sterically hindered nature of thesecompounds on the catalyst surface5-7.

For this reason, the removal of the DBTs by HDS, to give thedesired low levels of sulfur in diesel, requires high temperatureand H2 pressure conditions and subsequently a bigger reactorsize, as well as an active catalyst. From an environmental andeconomic viewpoint, it is extremely desirable to develop analternative, more energy-efficient desulfurization process for theproduction of virtually sulfur-free fuel.

Reported deep desulfurization processes include, but arenot limited to, selective adsorption6, extraction with ionicliquids7, oxidative desulfurization (ODS)8-11, biodesulfu-rization12, and other processes13. Due to a short reaction timeat ambient conditions, high efficiency and selectivity, ODScombined with extraction is regarded to be among thepromising processes in this regard. In this process, sulfur-containing species like sulfides, BT, DBT and alkyl-relatedderivatives are transformed into their correspondingsulfoxides or sulfones species, which are then removed in asecond step.

Various studies on the ODS process have employeddifferent oxidizing agents, such as NO2

14 tert-butylhydroxide11 and H2O2

8-11. Hydrogen peroxide is commonlyused as an oxidizing reagent due to its relatively low price,environmental compatibility and commercial availability.H2O2 is effective in the presence of a transition metal-basedcatalyst and in acid media8-11. Examples of transition metal-based systems are tungstophosphoric acid8, Na2WO4 +[(n-C4H9)4N]Cl15, K12WZnMn2(ZnW9O34)2 + [CH3(n-C8H17)3N]Cl16, 2-NO2C6H4SeO2H17, hemoglobin18 and othertransition metal-based oxides1, 2, 13.

Herein we describe a simple and highly effective catalyticsystem for the oxidation of DBTs. The catalytic system wasevaluated for the removal of sulfur-containing compounds indiesel19-25. Although, there is still room for improvement for

the catalyst and the process overall, which may have evenbetter results of less than 10 ppm sulfur.

OXIDATION OF MODEL SULFUR COMPOUNDS

The catalyst system for the oxidation reaction is composedof sodium tungstate (Na2WO4, 0.2 g), acetic acid(CH3CO2H, 5 mL) and hydrogen peroxide (30% H2O2/H2O,1 mL) as an oxidizing agent. In a round-bottom vessel, theoxidation reaction was carried out with separate modelsolutions of DBT and 4,6-DMDBT in octane (500 ppm S) attemperatures of 30 °C, 50 °C, 70 °C and 90 °C.

In each run, the Na2WO4 catalyst was observed to dissolvegradually in the mixture, forming first an emulsion and thenan opaque lower layer with time, Fig. 1.

The opaque emulsion lower layer was observed to transfergradually to form a white milk-like layer once the mixturetemperature reached 70 ºC. At this temperature, a biphasicsystem was clearly observed, Fig. 2.

In this biphasic system, the upper layer is clear, and hasbeen proven to be the hydrocarbon layer (the octane). Thelower layer is aqueous and milk-like and contains mainlywater, acetic acid and some of the sulfones. Trace amounts ofsulfone were also observed in the upper layer and mostprobably at the interface of both layers.

Throughout the reaction, stirring was continuous, and theprogress of the reaction was monitored periodically bywithdrawing 0.1 mL aliquots of the upper hydrocarbon layer


Fig. 1. The first formation of the emulsion mixture.

Fig. 2. Photo of the flask showing a biphasic system formation at 70 °C.


It is worth mentioning that this new ODS catalytic systemefficiently reached full conversion of the sulfur compounds tosulfones without the addition of a phase transfer agent (PTA).Noyori et al. 27, previously reported the use of Na2WO4 withphosphoric acid and a quaternary ammonium salt promoter forthe oxidation of diphenyl sulfide to give the correspondingsulfone. In the absence of the quaternary ammon ium salt PTA,no oxidation was observed in their system.

OXIDATION OF A HYDROTREATED DIESEL

The new oxidation system was then tested on a commercialdiesel sample supplied by Rabigh Refinery. The diesel hightemperature (HT) boiling ranges of 250 °C - 350 °C has 1,100ppm sulfur content. A selective sulfur detector, a pulse flamephotometric detector (PFPD), was especially useful to monitorchanges in the concentration of the different sulfur com -pounds existing in the diesel. In a series of extensive tests atvarious concentration levels of standard sulfur compounds,the sensitivity, linearity, and accuracy of the technique asapplied to the range of sulfur compounds was established.

The chromatogram in Fig. 5 shows the analysis of the HTdiesel sample using GC-PFPD.

In this chromatogram, only the most abundant sulfurcompounds, according to their concentration, can be seen. A

of the reaction mixture for GC-FID and other sulfuranalysis. Similar quantities were also withdrawn from thelower layer. Every sample was immersed immediately inliquid nitrogen to suspend the oxidation reaction. Figure 3shows the evolution of the chromatogram of DBT and 4,6-DMDBT with the reaction temperature.

It is observed that both DBT and 4,6-DMDBT are oxidizedto the corresponding sulfones indicated as DBTO2 and 4,6-DMDBTO2, respectively. It can also be observed that theconversion of the sulfur compounds into sulfones increaseswith temperature.

Figure 4 shows the conversion of the sulfur compounds as afunction of the temperature of the two model solutions aftertheir ODS treatment to prove the need (or otherwise) for thesodium tungstate catalytic system. This conversion, at adifferent reaction temperature, was calculated using thenormalized peak areas as obtained from the GC-FIDchromatograms.

Both DBT and 4,6-DMDBT reached their maximum fullconversion at 70 °C in less than an hour of reaction time. Inthe absence of Na2WO4, using similar amounts ofH2O2/CH3CO2H, poor conversion was observed.

Shiraishi et al.5 and Otsuki et al.26, have calculated theelectron densities of sulfur atoms for DBT and 4,6-DMDBT at5.758 and 5.760, respectively. Such trends have been attributedto two main factors: (a) reduced availability of the lone pairelectrons, and (b) steric strain in the reaction products.

Fig. 3. GC-FID chromatographs of model solutions upon ODS treatment.

Fig. 5. GC-PFPD chromatogram of the sulfur compounds in the HT diesel.

BT Benzothiophene (Internal Standard)

MEBT Methyl ethyl benzothiophene

DBT Dibenzothiophene

4-MDBT 4-Methyl dibenzothiophene

3-MDBT 3-Methyl dibenzothiophene

4,6-DMDBT 4,6-Dimethyl dibenzothiophene



Tri-MDBT Tri-methyl dibenzothiophene

Tri-EDBT Tri-ethyl dibenzothiophene

C3-DBT C3-Dibenzothiophene

Fig. 4. The influence of ODS catalytic system on sulfur conversion of DBT (º) and4,6-DMDBT (*) at different temperatures.

total of 79 different sulfur compounds were identified in thisdiesel, with DBT and its alkyl derivatives being the majorsulfur compounds.

In this chromatogram, the higher intensity peaks ofcompounds, such as 4,6-DMDBT, 4-MDBT and DBT wereassigned for comparison with the fingerprint of standardsamples analyzed under similar analytical conditions. The restof the peaks were compared to several publications in whichsimilar conditions and column specifications had been used.

It can be noted from the chromatogram that the presence ofDBT and its alkyls is predominant since conventional HDStechniques are unable to remove these refractory sulfurcompounds. In these experiments, the BT was added as aninternal standard before injection in the GC-PFPD. Theknown concentration was used to calculate the concentrationof other sulfur compounds.

The sulfur containing compounds in the diesel sample wereobserved to be oxidized to their corresponding sulfones, andthese were further extracted with methanol, Fig. 6. The sulfurconcentration was successfully reduced by ODS and then byextraction by more than 92% and 97%, respectively. In areaction time of less than an hour, the total sulfur content in thetreated diesel sample was reduced from 1,100 ppm to less than39 ppm; this represents a total sulfur removal efficiency of 97%.The catalyst was mainly recovered in the aqueous lower layerand reused effectively for six consecutive new batches of ODSprocesses, topping up the hydrogen peroxide intake each time.

DISCUSSION ABOUT THE ODS REACTION

Generally, in the ODS reactions, the divalent sulfur atom of theorganic sulfur compounds undergoes the electrophonic additionof oxygen atoms from the hydrogen peroxide to form thesulfone, i.e., hexavalent sulfur. The chemical and physicalproperties of sulfones are significantly different from those offuel oil hydrocarbons. Therefore, they can be easily removed byconventional separation methods, such as distillation, solventextraction, adsorption and decomposition10-13. Figure 7 is aschematic diagram of the process of the overall ODS reaction.

DISCUSSION OF THE ODS MECHANISM

The tungstate-based catalyst has been shown effective for theoxidation of the others into sulfones using H2O2 as theoxidant in a two-liquid phase system together with a phasetransfer catalyst (PTC)16-18. Several mechanisms of ODSreactions have been proposed previously12, 13, 18. The homo -geneous biphasic ODS system described above is simple anduses no PTA. Figure 8 is a detailed view of the reactionmechanism.

Once the catalyst is mixed with the hydrogen peroxide andthe diesel fuel in acetic acid, the biphasic catalyst system startsto form at room temperature. We suggest that WO42-anionreacts in two steps with two molecules of H2O2 in sequentialsubstitution reactions; in each step a W=O group is replacedby a W (O2) group and H2O is displaced. The resultingperoxotungstate [(-O)2 W (O2)2] anion then reacts bysequential oxygen atom transfer to the sulfur of R2S to formR2SO (sulfoxide) then R2SO2 (sulfone), which can beextracted in the aqueous phase. The peroxotungstate can beregenerated on the interface between the two layers or in the


Fig. 6. Changes in the concentration of the organic sulfur-containing compoundsin HT diesel after the ODS treatment that was followed by methanol extraction.

0

20

40

60

80

100

BTM

EBT

DBT

4MDBT

4,6DM

DBT

DieselAfter ODS

S

S

S

CH3

C2H5

S

H3C

H3C

S

H3C

S

H3C CH3

S

H3C

CH3S

H3C

CH3

H3C

SC2H5

C2H5

C2H5

SC3H7

,1,4-

DMDBT

1,3-

DMDBT

TriM

DBT

TriED

BT

C3DBT

Sulf

ur

con

cen

trat

ion

(pp

m)

S

S

S

CH3

C2H5

S

H3C

H3C

S

H3C

S

H3C CH3

S

H3C

CH3S

H3C

CH3

H3C

SC2H5

C2H5

C2H5

SC3H7

Diesel

After ODS

After extraction

Fig. 7. The overall ODS reaction and a sketch of the biphasic system.

Fig. 8. Proposed ODS reaction mechanism.

S

Polar Phase

Non polar Phase

2H2O2H2O2

2H2O22H2O

W

Na+

Na+

O O

O

H

H

R2R 1S

R2R1

S

R2R1

O O O

R1=Aryl/CH3 R2=Aryl/CH3

O

O

O

W

Na+

Na+O

O

W

Na+

Na+

O O

O

O

W

Na+

Na+O

O

Sulfone Precipitate

OO

OO

O

H

H

O

O

O

H2O

VIVI

VI VI

two steps substitution of O2- by O2

2-

2 Oxygen atoms transfer reaction


CONCLUSION

We conclude that, at modest temperatures and underatmospheric pressure, our ODS catalytic system, comprised ofNa2WO4 H2O2 and acetic acid, is effective for removing mostof the last few hundred ppm of HDS-persistent organic sulfur-containing compounds in diesel. Therefore, it can be envisagedthat an ODS unit would be added as a complementary posttreatment unit to the current HDS facilities, Fig. 10.

By achieving a sulfur content of less than 50 ppm in diesel,the current ODS process, when combined with extraction, hasthe potential to meet future environmental legislations1-4.

ACKNOWLEDGMENT

The authors wish to thank Saudi Aramco management fortheir support and permission to present the informationcontained in this article. We would also like to thank Dr.Omer AbdulHamid, Mr. Khalil Al-Shafei, Dr. Bashir Al-Dabbousi and Mr. Richard Horner from Saudi Aramco fortheir fruitful discussions, directions and usual support. Thanksalso to Dr. Sami Barri for the diesel analysis in the ImperialCollege. Many thanks as well to the management andcolleagues at the Inorganic Chemistry Laboratory at OxfordUniversity for their outstanding collaboration.

REFERENCES

1. Yang, R.T., Hernandez-Maldonado, A.J. and Yang, F.H.:“Desulfurization of Transportation Fuels with Zeolitesunder Ambient Conditions,” Science, Vol. 301, No. 5,629,2003, pp. 79-81.

2. Gosling, C.D., Gembicki, V.A., Gatan, R.M., Cavanna, A.and Molinari, D.: “The Role of Oxidative Desulfurizationin an Effective ULSD Strategy,” (UOP LLC), Chemindix,Bahrain, 2004.

3. Turaga, U.T. and Choudhary, T.V.: “Desulfurization and NovelProcess for Removal of Sulfur from Hydrocarbons,”(ConocoPhillips Company, USA), Application: WO, 2006, p. 31.

4. Berti, V. and Iannibello, A.: “Hydrodesulfurization ofPetroleum Residues: Principles and Applications,” 1975, p.322.

5. Shiraishi, Y., et al.: “Desulfurization of Light Oil byReaction of Sulfur Compounds with Chloramine TResulting in Sulfimides Formation,” Chemical

Communications, Vol. 14, 2001, pp. 1,256-1,257.

6. McKinley, S.G. and Angelici, R.J.: “Deep Desulfurizationby Selective Adsorption of Dibenzothiophenes on Ag+/SBA-15 and Ag+/SiO2,” Chemical Communications, Vol. 20,2003, pp. 2,620-2,621.

7. Bosmann, A., et al.: “Deep Desulfurization of Diesel Fuelby Extraction with Ionic Liquids,” Chemical

Communications, Vol. 23, 2003, pp. 2,494-2,495.

aqueous phase in the presence of an adequate supply of H2O2.Sulfone is known to be slightly more polar than sulfurcompounds, so they will form a white precipitate. The wholeprocess will result in a biphasic solution in which the upperlayer becomes almost sulfur-free diesel.

The tungstate anion has the normal tetrahedral structure.Figure 9 shows the Raman spectroscopy of the catalyst beforeand after the ODS reaction.

The Raman stretching above 900 cm-1 is usually attributed tothe W=O stretching while the W-O bend vibration is around 320cm-1 20-22. The standard STDH has bands at 928 cm-1, 890 cm-1,836 cm-1 and 331 cm-1 in its ordinary tetrahedral struc ture. Afterthe ODS reaction, the new bands are seen at 970 cm-1, 950 cm-1,895 cm-1 and 312 cm-1, which suggest the presence of differentforms or more than one peroxotungstate system.

The electrophilicity of the peroxotungstate intermediate ismuch higher than that of H2O2 so it will participate effectivelyin the oxidation of sulfur atoms. The ligation on the W centerwould increase the reactivity of the peroxoligands, and themetal center (W) has an unchanged oxidation number of VIthroughout the whole process. The sulfur compound in theform of R2S is nucleophilic due to the presence of two lonepairs of electrons on the sulfur, which can be donated to formbonds with oxygen from the peroxotungstate.

The tungstate catalyst is soluble in the acetic acid solutionand forms a biphasic catalyst system. The role of the aceticacid in this reaction may be to increase the dispersion of thecatalyst and to promote and possibly to protonate oxo andperoxo groups of the tungstate system9-11, 14, 19, 25.

Fig. 9. Raman spectra of STDH (Catalyst) and DBTSTDH (Product).

Fig. 10. General scheme of ODS process post HDS unit.

Conventional HDS

H2S

H

D

S

ODS

ULSD

Extraction

Sulfones

H 2

ODS Catalytic System

Diesel Feed

8. Yazu, K., Makino, M. and Ukegawa, K.: “OxidativeDesulfurization of Diesel Oil with Hydrogen Peroxide inthe Presence of Acid Catalyst in Diesel Oil/Acetic AcidBiphasic System,” Chemistry Letters, Vol. 33, No. 10,2004, pp. 1,306-1307.

9. Campos-Martin, J.M., Capel-Sanchez, M.C. and Fierro,J.L.G.: “Highly Efficient Deep Desulfurization of Fuels byChemical Oxidation,” Green Chemistry, Vol. 6, No. 11,2004, pp. 557-562.

10. Garcia-Gutierrez, J.L., et al.: “Ultra-Deep OxidativeDesulfurization of Diesel Fuel with H2O2 Catalyzed underMild Conditions by Polymolybdates Supported onAl2O3,” Applied Catalysis, A: General, Vol. 305, No. 1,2006, pp. 15-20.

11. Wang, D., et al., “Oxidative Desulfurization of Fuel Oil,Part I. Oxidation of Dibenzothiophenes using Tert-ButylHydroperoxide,” Applied Catalysis, A: General, Vol. 253,No. 1, 2003, pp. 91-99.

12. Yu, B., et al.: “Deep Desulfurization of Diesel Oil andCrude Oils by a Newly Isolated RhodococcusErythropolis Strain,” Applied and EnvironmentalMicrobiology, Vol. 72, No. 1, 2006, pp. 54-58.

13. Song, C. and Ma, X.: “New Design Approaches to Ultra-Clean Diesel Fuels by Deep Desulfurization and DeepDearomatization,” Applied Catalysis, B: Environmental,Vol. 41, Nos. 1-2, 2003, pp. 207-238.

14. Tam, P.S., Kittrell, J.R. and Eldridge, J.W.:“Desulfurization of Fuel Oil by Oxidation andExtraction. Part 1. Enhancement of Extraction Oil Yield,”Industrial & Engineering Chemistry Research, Vol. 29,No. 3, 1990, pp. 321-324.

15. Stec, Z., et al.: “Oxidation of Sulfides with H2O2

Catalyzed by Na2WO4 under Phase-Transfer Conditions,”Polish Journal of Chemistry, Vol. 70, No. 9, 1996, pp.1,121-1,123.

16. Neumann, R. and Juwiler, D.: “Oxidations withHydrogen Peroxide Catalyzed by the[WZnMn(II)2(ZnW9O34)2]12- Polyoxometalate,”Tetrahedron, Vol. 52, No. 26, 1996, pp. 8,781-8,788.

17. Reich, H.J., Chow, F. and Peake, S.L.: “Seleninic Acids as Catalysts for Oxidations of Olefins and Sulfides usingHydrogen Peroxide,” Synthesis, Vol. 4, 1978, pp. 299-301.

18. Klyachko, N.L. and Klibanov, A.M.: “Oxidation ofDibenzothiophene Catalyzed by Hemoglobin and otherHemoproteins in Various Aqueous-Organic Media,”Applied Biochemistry and Biotechnology, Vol. 37, No. 1, 1992, pp. 53-68.

19. Xiao, T., Shi, H., Al-Shahrani, F.M. and Green, M.:“Hydrocarbon Recovery from Sulfones Formed byOxidative Desulfurization (ODS) Process,” paper IP244-561539, April 20, 2008.

20. Al-Shahrani, F.M., Xiao, T., Martinie, G. and Green, M.:“Catalytic Process for Deep Oxidative Desulfurization ofLiquid Transportation Fuels,” WO 2007103440, U.S.Pat. Appl. Publ. 2007, 35 pp.

21. Martinie, G.M., Al-Shahrani, F.M. and Dabbousi, B.O.:“Diesel Oil Desulfurization by Oxidation andExtraction,” U.S. 2007051667, U.S. Pat. Appl. Publ.2007, 9 pp.

22. Martinie, G.D., Al-Shahrani, F.M. and Dabbousi, B.O.:“Process for Treating a Sulfur-Containing Spent CausticRefinery Stream using a Membrane Electrolyzer Poweredby a Fuel Cell,” U.S. 2006254930, U.S. Pat. Appl. Publ.2006, 12 pp.

23. Martinie, G.D. and Al-Shahrani, F.M.: “Reactive Extrac -tion of Sulfur Compounds from Hydrocarbon Streams,”WO 2005066313, PCT Int. Appl. 2005, 24 pp.

24. Al-Shahrani, F.M., Xiao, T., Llewellyn, S., et al.:“Desulfurization of Diesel via the H2O2 Oxidation ofAromatic Sulfides to Sulfones using a TungstateCatalyst,“ Journal of Applied Catalysis, B:Environmental, Vol. 73, 2007, pp. 311-316.

25. Al Shahrani, F.M.: “Oxidative Desulfurization of DieselFuels,” Ph.D. thesis, 2008, University of Oxford Press,Oxford, UK.

26. Otsuki, S., Nonaka, T., Takashima, N., et al.: EnergyFuels, Vol. 14, 2000, p. 1,232.

27. Noyori, R., Aoki, M. and Sato, K.: “Green Oxidationwith Aqueous Hydrogen Peroxide,” ChemicalCommunications, Vol. 16, 2003, pp. 1,977-1,986.



Dr. Abdennour Bourane is a ResearchScientist at the Research andDevelopment Center (R&DC). He isleading activities within the CleanFuels project of the Downstream andStrategic Program. Prior to joiningSaudi Aramco he worked at the

Institute of Research on Catalysis and Environment at Lyon(IRCELyon), France and at the Chemical EngineeringDepartment of Kansas State University, Manhattan, KS.Abdennour has more than 20 publications in internationalpeer-reviewed journals.

Abdennour received his Ph.D. degree in Chemistry fromthe University of Lyon, Lyon, France.

Dr. Omer R. Koseoglu is a ResearchScience Consultant at the Research andDevelopment Center (R&DC). He isleading the Clean Petroleum Fuelsproject of the Downstream andStrategic Program.

Omer has a Ph.D. degree inChemical Engineering from the University of Toronto,Toronto, Ontario, Canada; a M.S. degree in Chemistryfrom Brock University, St. Catharines, Ontario, Canada;and a B.S. degree in Chemical Engineering from GaziUniversity, Ankara, Turkey. Prior to joining SaudiAramco, he worked for CONOCO, Inc. at theTechnology Development Center in Ponca City, OK, IFPNorth America/Hydrocarbon Research, Inc. (HRI); andShell Canada Limited at the Oakville Research Center.Omer has numerous publications and is a registeredprofessional engineer.

Professor Malcolm L.H. Green wasProfessor and Head of InorganicChemistry at Oxford University from1989-2003. He then became anEmeritus Research Professor. Malcolmis also the co-founder of the OxfordCatalysis Group.

He received a B.S. and Ph.D. degree from LondonUniversity, London, UK, the latter in 1959. Malcolmcarried out research at Cambridge University and then atOxford University in organotransition metal chemistry,homogeneous and heterogeneous catalysis and, morerecently, the chemistry of carbon nanotubes. He has over700 publications and was elected Fellow of the RoyalSociety of Chemistry in 1985.

BIOGRAPHIES

Dr. Farhan M. Al-Shahrani rejoinedSaudi Aramco’s Research andDevelopment Center (R&DC) inAugust 2008 after his successfulcompletion of a 4 year advanceddegree program at the University ofOxford, Oxford, UK.

Farhan first joined Saudi Aramco in 1993 in the CollegeDegree Program Non-Employee (CDPNE) program. In1998 he received a third honor B.S. degree in IndustrialChemistry from King Fahd University of Petroleum andMinerals (KFUPM), Dhahran, Saudi Arabia. Since thattime, he joined the R&DC and worked in various units,including advanced instrument, crude evaluation, process,geochemistry and the environmental unit. In 2003, Farhanreceived his M.S. degree in Chemistry, also from KFUPMas a second honor.

Under the supervision of Prof. Malcolm L.H. Green,Farhan’s Ph.D. thesis research focused on oxidative desulfu-rization of diesel fuels, which resulted in the filing of twointernational patents. To date, he has five registered patentsand more than 12 peer-reviewed papers.

While in Oxford, Farhan was able to launch a SaudiOxford Society that he voluntarily led for two consecutiveyears. Moreover, he worked as the chairperson of thescientific committee for the 2nd International SaudiInnovation Conference hosted last June by the University ofLeeds. Farhan is a member of the American ChemicalSociety (ACS) and the prestigious Royal Society ofChemistry (RSC).

Dr. Tiacun Xiao earned his Ph.D.degree in Heterogeneous Catalysisfrom the Chinese Academy of Science,Beijing, China in 1993. As anAssociate Professor at ShandongUniversity in China, he spent the next6 years collaborating on both

petrochemical and environmental projects with Sinopec, theShandong Provincial Government and the World Bank. In1999, Tiacun went to Oxford University and joined Prof.Malcolm Green's Wolfson Catalysis Center as a RoyalSociety BP Amoco Research Fellow. Since then, he has beenappointed a Visiting Professor at the Beijing University ofChemical Technology, Beijing, China, a Lecturing Professorat the Eastern China University of Science and Technology,Shanghai, China and a Guest Professor at the GuizhouUniversity, Guiyang, China. He has published over 100papers on catalysis, filed seven patents and received manyawards for his research both in China and in the UK.

Recently and jointly with Prof. Green, Tiacun was ableto launch the Oxford Catalysis Group as a new spin-offcompany of the University of Oxford.

ABSTRACT

The abrasive pre-Khuff sandstones, combined with highdownhole temperatures and the propensity for bottom-holeassembly (BHA) and bit sticking, present a uniquely hostiledrilling environment. These limit run durations and the abilityto optimize the rate of penetration (ROP) with the use ofconventional rotary assemblies, positive displacement mudmotors (PDMs)/conventional turbodrills and/or rotarysteerable systems. Catastrophic damage or loss of drill strings,poor hole quality and logging problems are common, evenwith the advancements in polycrystalline diamond compact(PDC) bit technologies.

Of the systems listed above, historically turbodrillingsystems have best addressed the high temperatures and theabrasive nature of the pre-Khuff formations and held thepotential for drilling economics optimization, but they havebeen unsuccessful in addressing bit sticking challenges. Thedevelopment of best practices produced only marginal resultsbecause they require surface intervention, and therefore do notfully address sticking problems (in particular, bit sticking).

The engineering challenge was to develop a downholedevice that automatically engages and imparts sufficient drillstring torque to maintain bit rotation. The turbodrill devicedisengages when conditions return to normal and returns theoperation to high productivity drilling without surfaceintervention. The turbodrill device, coupled withadvancements in BHA design, stabilizer and jar placementalong with formation characterization and drill bit technology,is the solution to bit sticking incidents.

Presented with this advancement in turbodrillingtechnology, the Operator/Service Company team hascompleted trials using this technology and presents data thatsupports the use and benefits of anti-sticking technologies.With this success, the team has regained focus on drillingoptimization and reset the goal for single run-casing point tocasing point.

INTRODUCTION

Saudi Aramco continually seeks ways to improve drillingefficiencies through the difficult pre-Khuff formations. Thisarticle is about a fortuitous trial of last resort that hasdelivered favorable results.

In Saudi Arabia, pre-Khuff formations (Unayzah, Jauf,Tawil, Sharawra, Qusaiba, Sarah, Qasim and Saq) areencountered at depths between 13,000 ft and 17,000 ft.These strata primarily comprise sandstones interbedded withshales, limestone, dolomite, anhydrite and siltstones.Sandstones with some siltstone predominate in the topUnayzah strata downward through the Qusaiba. At thebottom, the Sarah can also include some interbedded shale.The Unayzah and Jauf are generally characterized by hard,abrasive sandstones interbedded with shale and siltstone.Unconfined compressive strengths can reach 40,000 psi withinternal angles of friction ranging from 25° to 75°.Hardness, abrasiveness, toughness, irregularity in size andorientation of rock constituents, and problems with stickingall contribute to a significant challenge and expenseassociated with drilling in the pre-Khuff formations1-3. Highwear rates on bits and bottom-hole assembly (BHA)components present a significant potential for prematureequipment failures, limit bottom rotating time, andnecessitate long and frequent trips.

The Upper pre-Khuff (Unayzah to Jauf) strata are the mostdifficult of the pre-Khuff formations to drill. These stratatypically consist of very irregular, fine to coarse grainedpebbles and conglomerates that can vary significantly in theirdimensions and hardnesses (both in adjacent wells and atdifferent depths in a particular well), and the Jauf formationmay also contain pyrite.

Pre-Khuff reservoirs are an important source of present-daySaudi Arabian nonassociated gas production. Saudi Arabia isprogressively moving toward a significant increase in gasproduction. The expected growth is primarily for domesticfuel and petrochemical feedstock, although Saudi Arabia isalso a large exporter of natural gas liquids (NGLs). To meetthese goals, significant portions of Saudi Aramco drillingassets have been directed toward pre-Khuff onshore andoffshore gas exploration and development during the pastseveral years.

Saudi Aramco aggressively seeks drilling solutions thatmitigate inefficiencies. This article describes drilling the pre-Khuff sections in two offshore trial wells, which will be calledTrial Well “1” and Trial Well “2” in this article. A total of 11turbodrill with diamond impregnated bit runs, during 661rotating hours, had four principal goals:


Innovative Solution for Drilling Pre-KhuffFormations in Saudi Arabia UtilizingTurbodrill and Impregnated Bits

Authors: Gabriel D. Carrillo, Usman Farid, Michael Albrecht, Perry Cook, Nouman Feroze and Kenneth Nevlud


wear. This makes long drilling runs a typical and expectedresult. The vendor has spent years matching diamondimpregnated bit performance and run life to the turbodrill.Diamond impregnated bit cutting structures with increasedblade heights enable the incorporation of larger volumes ofdiamond material, thus longer bit life, into turbodrill bitcutting structures6. Bit aggressivity can be increased with useof larger diamonds in the impregnation mix (and vice versa)and/or modified by changing the number of blades. Cuttingstructure geometries also enhance nose and shoulderdurability (and bit run life) without interfering with gaugeprotection. Thermally stable polycrystalline (TSP) inserts arepositioned on the gauge and shoulders to ensure the bit hasthe capability to drill a gauge hole in hard and abrasive rock,and increase durability and wear resistance in the shoulders.Incorporated PDC cutters in the cone area improve ROP.

While a matched bit and turbodrill promised long run life,bit sticking presented what seemed an insurmountableproblem. If jarring was required to free a stuck bit attached toa turbodrill, there was a high probability of damage to theturbodrill requiring a tool replacement trip.

DEVELOPMENT OF MECHANICAL RECOVERY FROMSTICKING

While every effort was made to optimize performance anddurability potentials for all parts of the drilling system, pre-Khuff turbodrilling could be successful only if bit sticking eventswere avoided. Some months prior to the Well 1 problems, thevendor ran a series of development trials on a new optional toolfeature that allows drillstring torque to be directly applied to adrill bit mounted on a turbodrill. The purpose of this device isto prevent the bit sticking, and it had shown solid potentialduring the initial prototype tests. This tool feature was disclosedand Saudi Aramco agreed to a trial.

The device works as follows: If, while drilling ahead inrotary, the turbodrill drive shaft (attached to the bit) begins toslow/stall, a locking clutch (LC1) mechanism automatically(with no intervention from the surface) engages and transmitsstring torque via the drive shaft to the bit to prevent the stall.As most sticking originates during times in which a turbodrillis stalled, the clutch will prevent most incidents of bit sticking.Subsequently, as sticking forces are overcome, the need forstring torque decreases, and the LC1 automatically disengages(again without surface intervention) and returns the system tohigh productivity turbodrilling. In turbodrilling conditions inwhich the potential for bit sticking is a significant operationalrisk, the LC1 showed promise as a very useful innovation, anda turbodrilling trial commenced using the innovative feature.

At the time of the Saudi Aramco trial, experience with theLC1 was limited to about 1,800 hours of field testing. Based onperformance data derived from this testing, Saudi Aramco andthe vendor elected to mitigate the risk of a catastrophic bitsticking event by limiting the operational on-bottom run time to

• Decreasing trip frequency.

• Decreasing bit and BHA component failures that lead tofishing.

• Increasing productive, on-bottom bit life.

• Increasing the rate of penetration (ROP) through use ofhigh efficiency downhole drives and analyticallyengineered BHAs.

Historically, vertical turbodrill runs through the pre-Khuffformation have been unsuccessful because of their inability totransmit rotary torque to the bit when sticking events occur4.Still, a turbodrill paired with a specially designed diamondimpregnated drill bit promises a favorable response to all ofthe above goals. Although the bit sticking problems clearlyremained in everyone’s mind, interest in the tool remained as aresult of its potential for durability and productivity in theevent the sticking problems could be prevented5. This articlebegins with an offshore well, Trial Well 1, at a point wherepre-Khuff problems had become acute. The well has had atroubled history. At a depth of 16,617 ft in the Unayzahformation, a twist-off occurred, necessitating a sidetrack. Thesidetrack was started at the top of the Unayzah at a depth of16,200 ft with a positive displacement mud motor (PDM) andpolycrystalline diamond compact (PDC) bit. Saudi Aramco’spre-Khuff drilling is typically achieved with PDC bits drilledwith rotary power. Because of the sidetrack, however, PDCwith rotary was not possible in Trial Well 1. The assemblycould not, of course, negotiate the change of direction at thesidetrack.

The utilization of a down drive system increases therotational speed and torque delivered to the drill bit, whileisolating these increased forces from the drillstring. Thedrillstring rotary speed and torque required to drill effectivelyis reduced. This reduces the stress and tortuosity induced onBHA components and improves drillstring reliability.

At Unayzah depths in Trial Well 1, temperatures of 340 °Fwere encountered. These temperatures cast doubt onreliability expectations for key PDM rubber components.Turbodrills easily withstand much higher temperatures, andin spite of past bit-sticking problems, there was little to lose:It was an opportunity for the evaluation of innovativeturbodrill technology.

TURBODRILL AND MATCHED BIT CHARACTERISTICS

Turbodrills running diamond impregnated drill bits arenormally an excellent combination in hard, abrasive materials.Diamonds easily cut through all hard rock. Although diamondexposure in a diamond impregnated drill bit is quite small, thehigh rotating speeds of the turbodrill (1,000 rpm to 1,200rpm or more) produce attractive ROPs because the number ofrotations is so high.

Turbodrills are similar to aircraft engines. Power isproduced by rotating vanes that are subjected to very little

80 hours. This time period was sufficient to provide bothengineering application and fiscal justification for the trial,which would determine future use of the turbodrilling assemblyequipped with the locking clutch device.

For now, summarizing ahead, it can be mentioned that theturbodrills equipped with the LC1 produced no drillingdisruptions of any kind, including bit sticking or lockingclutch equipment failure.

TRIAL PROGRAM

Key Saudi Aramco goals for a turbodrilling trial were:Operational cost reduction, mitigation in the requirednumber of trips, avoidance of downhole component failures,increased on-bottom drilling time, and an evaluation ofturbodrilling performance in hard, high temperature pre-Khuff rock.

On historical turbodrill runs, Saudi Aramco has had anumber of bit sticking problems and almost quit usingturbodrills across the pre-Khuff. The intervening yearsbrought stabilization engineering and development of matcheddiamond impregnated bits designed for drilling efficiency andfor extended run durations.

Turbodrilled hole quality and straightness are greatlyinfluenced by BHA design. To ensure optimization, thevendor’s engineers in Houston used proprietary BHAsimulation software to model critical rpm and stabilizerplacement.

Rig hydraulic equipment and drilling fluid characteristicsare another key factor in turbodrill optimization. Availablepump pressures and flows are optimized to turbodrillrequirements with proprietary software used by on-rigturbodrill supervisors prior to runs and regularly duringdrilling.

Turbodrilling crews are, obviously, the controlling influenceon tool performance. The turbodrilling supervisor isresponsible for training the rig crew on drilling safety andprocedures, and ensures there is no deviation from procedureduring operations. This supervisor also works closely with theMud Engineer to be aware of changes to the mud and re-optimize the tool when changes occur. The crews help preventaccidents of all types, including bit sticking, and ensure betteroptimized drilling performance.

ORIGINAL WELL 1

The original Well 1 is an offshore well. The well targets apre-Khuff reservoir drilled with PDC bits and rotary. Thewell has had a troubled history. At a depth of 16,617 ft, wellshort of the planned total depth (TD), in the UnayzahFormation, a twist-off occurred that necessitated continuingthe well via a sidetrack that begins at the top of the Unayzahformation (16,200 ft). This sidetrack was to becometurbodrilling Trial Well 1.

OFFSET WELL

Well 1 could not be used for offset comparison to the TrialWell 1 sidetrack because it had not reached sufficient depth.Saudi Aramco, therefore, selected another offshore pre-Khuffwell for comparative evaluation to the Trial Well 1 sidetrack.In this article, the offset is referred to as Offset Well. In theOffset Well, the top of the Unayzah begins at 16,416 ft, andTD 17,970 ft.

The Offset Well was drilled with 17 rotary runs usingPDC bits.

TRIAL WELL 1 SIDETRACK

The Trial Well 1 sidetrack begins at a depth of 16,200 ft andwas competed at 16,394 ft. This portion of the well is notincluded in summaries that are shown below.

High bottom-hole temperatures (approximately 350 °F) are aproblem at pre-Khuff depths. Because of temperature, PDMshave unsatisfactory operational life and are not suitable fordrilling in these sections. Moreover, the utilization of adownhole drive system, which does not allow drillstring torqueto be transmitted to the bit, disqualifies PDMs and con -ventional turbodrills alike from drilling potential bit stickingsequences. The wish to avoid the reoccurrence of catastrophicexperiences with rotary drilling on the original well, combinedwith the incompatibility of a PDM, resulted in the turbodrillbeing the sole remaining alternative. Thus, a 43⁄4” turbodrillequipped with a locking clutch, and a matched diamondimpregnated bit was selected, subject to the 80 hour drillinglimit described above.

Trial No. 1 goals included: An evaluation of turbodrillingperformance and reliability, operational cost reduction inhard, high temperature pre-Khuff drilling, mitigation in therequired number of trips, avoidance of downhole componentfailures and increased on-bottom drilling time.

The first turbodrill trial run began at a depth of 16,394 ft.This tool drilled 377 ft in 73 hours. As indicated by surfacetorques during the run, bit sticking events did occur and wereovercome by engagement of the locking clutch. There were noproblems disruptive to drilling attributed to the turbodrill. Asa result, Saudi Aramco approved continuation of the trial, ona run-by-run basis, to a TD of 17,900 ft. A PDC bit on rotarydrilled 127 ft in a formation that was not conducive toefficient penetration by a diamond impregnated bit.

Trial No. 1 Run Summary

A total of 1,379 ft (six runs total, including five turbodrillruns and one PDC bit in rotary run) were drilled at anaverage ROP of 5.18 ft/hr. All bits were in good condition atthe end of their respective runs. The hole condition was good,and there was no spiraling. High temperatures had no adverseeffect on the turbodrill durability or performance. No loss ofproductive time was attributable to bit sticking or problemswith either the turbodrills with LC1s or the matched diamond



in the Trial Well 1 sidetrack, and results for both trials are,accordingly, beneficiaries of added credibility.

CONCLUSIONS

1. During this trial, there were no events in which bit stickingor BHA problems resulted in lost on-bottom drilling time.

2. The high temperature pre-Khuff environment had noadverse effect on turbodrill durability or performance.

3. Turbodrills equipped with the LC1 locking clutch and matcheddiamond impregnated bits drilled 11 runs. In addition, threePDC runs are included for a total of 3,863 ft drilled incomparable pre-Khuff sections in two trial wells, Table 1.

4. During these runs there were no events causing downtimerelated to either turbodrills or drill bits.

5. Turbodrills equipped with the LC1 were tripped fromthe well after a maximum of 80 on-bottom hours. Based

impregnated drill bits during any of this group of trial runs.Favorable results were achieved for all trial goals.

TRIAL WELL 2

Based on the favorable results in the Trial Well 1 sidetrack,Saudi Aramco authorized continuation of the turbodrill withLC1 trials in the pre-Khuff sections of Trial Well 2. The 80hour drilling limit was continued.

Primary goals for Trial Well 2 were the same as for theTrial Well 1 sidetrack. Of additional importance, SaudiAramco wanted to determine whether or not the favorableTrial Well 1 results could be consistently expected, and boththe Offset Well and the Trial Well 1 sidetrack served asoffsets for Trial Well 2.

Trial No. 2 Run Summary

A total of 2,357 ft (eight runs total, including six turbodrillruns) were drilled at an average ROP of 4.9 ft/hr. Two PDCbits on rotary, between the first and second turbodrill runs,drilled 171 ft. A 60 ft core run between the fifth and sixthturbodrill runs is not included in feet drilled. As with the firsttrial, hole condition was good, and no nonproductive timewas attributable to either turbodrills with LC1s or thematched diamond impregnated drill bits during the runs. TrialWell 2 results are exceptionally consistent with those produced

Table 1. Summary data

Runs Days Footage Days/ Ft/Day Ave.1,000 Ft Ft/Run

Offset Well 17 36.8 1781 20.7 48.4 104.8Trial Well “1” ST 6 22.5 15.6 14.9 67.1 251.0Trial Well “2” 8 35.3 2357 15.0 66.7 294.6

Fig. 1. Typical condition of post-run drill bits.

Fig. 2. Required trips.

0

4

8

12

16

20

Req

uir

ed T

rip

s

Offset Trial 1 Trial 2

17

6

8

Fig. 3. Days per 1,000 ft drilled.

0

5

10

15

20

25

Day

s /

1,00

0 Fe

et


20.7

14.9 15.0

on positive trial results, the limit on drilling time iscorrectly established.

6. All diamond impregnated bits were tripped from the wellin excellent condition after a maximum of 80 hours. Onebit was reused with good results. All bits possessedadditional life/value and their respective run lives couldhave been extended, Fig. 1.

7. The turbodrill and impregnated bit combination reducedthe tripping required by the offset well by more than 50%.This is a positive result for the trial goal pertaining totripping, Fig. 2.

8. Days per 1,000 ft drilled are 28% lower for the turbodrilland impregnated bit combination than for the offset well,Fig. 3. This result contributes positively to trial goals.

9. The impregnated drill bits more than doubled the feet drilledby PDC bits in the offset well. This contributes to a positiveresult for the trial goal of increasing time on-bottom, Fig. 4.

10. Feet drilled per day are 38% higher for the turbodrill,and impregnated bit combination than for the offset well.Again, this result is a positive trial result, Fig. 5.

11. Figures 6 and 7 show drilling performance com parisonbetween offset and Trial Wells with and withoutcoring runs.

12. It can be concluded from the study of reduction in daysper 1,000 ft drilled, and for the required number of runsthat turbodrilling with the innovative locking clutch andimpregnated bits produced important fiscal benefits.

In conclusion, the turbodrill locking device innovationhad a very positive impact on the vertical pre-Khuffdrilling program through two well trials. Saudi Aramco, inconjunction with Smith International, continues to seekand expand the applications for the concept whilesignificantly increasing value through optimization of theturbodrilling system.

ACKNOWLEDGMENTS

The authors wish to thank Saudi Aramco management fortheir permission to publish this article. Special thanks to W.H.Wamsley, for his valuable assistance and support in thepreparation of this article.


Fig. 4. Average ft drilled per run.

0

50

100

150

200

250

300

350

Ave

. Fee

t /

Ru

n


104.8

251.0

294.6

Fig. 5. Average ft per day.

0

10

20

30

40

50

60

70

80

Ave

. Fee

t /

Day


48.4

67.1 66.7

Fig. 6. Comparative depth vs. days.

Fig. 7. Comparative depth vs. days (including coring).


REFERENCES

1. Simpson, M.A., Zhou, S. and Nordquist, D.G.: “DrillingChallenges and Recent Advances of Pre-Khuff Wells, SaudiArabia,” presented at the SPE Technical Symposium of theSaudi Arabia Section, Dhahran, Saudi Arabia, June 7-9,2003.

2. Simpson, M.A., Zhou, S., Treece, M. and Rondon, C.:“Optimal Horizontal Drilling of Hard and AbrasiveUnayzah Sandstones,” SPE/IADC paper 85331, 2003.

3. Simpson, M.A., Zhou, S., Treece, M., et al.: “BreakthroughHorizontal Drilling Performance in Pre-Khuff Strata withSteerable Turbines,” SPE paper 90376, 2004.

4. Internal Report, “Definition of Bit Sticking Problem withTurbine in Pre-Khuff Sands,” Drilling Technology Unit,Drilling and Workover Engineering Department, SaudiAramco, circa 1998.

5. Nordquist, D. and Zhou, S.: “An Interim Report on BitSticking Problem and Recommended Solutions,” InternalReport, Saudi Aramco, October 2001.

6. Simpson, M.A., Roed, A.H., Al-Shammari, H.A. andHoekstra, D.: “Rotary Application of Low Matrix StrengthImpregnated and TSP Cutter Bits to Unayzah SandstoneDrilling,” SPE/IADC paper 77223, 2002.


Perry Cook is the Middle East AreaManager for Smith Drilling &Evaluation, responsible for theturbodrill product line. Perry startedhis oil field career with Baker Hughes,working for 7 years in the drillingfluids sector in the areas of technical

research and field operations. He joined Smith Neyrfor in2002 and has subsequently held field, technical,coordination and management positions in the UK, theU.S., Kazakhstan and Saudi Arabia. Perry is currentlybased in Abu Dhabi supporting all aspects of turbodrillbusiness development throughout the Middle East.

In 1995, he received his B.S. in Biotechnology from theUniversity of East Anglia, Norwich, UK.

Nouman Feroze is a PetroleumGeologist working as a Senior SalesEngineer for Smith Bits, based in Al-Khobar, Saudi Arabia, where he servesSaudi Aramco’s Exploration Groupand Joint Ventures Operators. Hestarted his career with Sperry Sun,

Pakistan and worked 2 years as a mud logger, then hejoined Smith Bits and worked in various locations in theMiddle East. Nouman has a total 11 years of oil fieldexperience.

He received his B.S. degree in Geology in 1994, and in1996 he received his M.S. degree in Petroleum Geology(Gold Medalist), both from the University of Karachi,Karachi, Pakistan.

Nouman is an active Society of Petroleum Engineers(SPE) member.

Kenneth Nevlud is a MechanicalEngineer with Smith Neyrfor, where heis currently the Manager of theNeyrfor Sustaining Engineering Group.He started his career with SmithInternational in 2000, spending 2 yearswith GeoDiamond focusing on bit

design before pursuing turbine design with Smith Neyrfor. In 2000, Kenny received two B.S. degrees, one in

Mechanical Engineering and the other in Mathematics,from The University of Texas at Austin, Austin, TX.

BIOGRAPHIES

Gabriel D. Carrillo began working forSaudi Aramco in 2007. He received hisM.S. degree in Petroleum Engineeringfrom Texas A&M University, CollegeStation, TX. Since 1994, he hasworked for ExxonMobil, BP Americaaround the world, and several small

independent companies in South America, where his jobsincluded Field Service Technician, Rig Supervisor andDrilling Engineer. Currently Gabriel works in theExploration Drilling Department where he monitors dailyactivities and plans upcoming events in a highly offshoreprofile well.

Usman Farid is an EngineeringSupervisor in Saudi Aramco’sExploration Drilling Department. Hebegan working with the company in2002 and over 23 years experience inrig drilling in the field, as well as in theoffice, up to the Drilling

Superintendent level. Usman also worked as a FishingEngineer and Sr. Drilling Instructor prior to joining thecompany. His job includes covering all engineering aspectsfrom planning to completion for high profile HPHToffshore gas exploration wells currently being drilled.

Usman graduated with a double B.S. degree in Mathand Physics and Petroleum Engineering from theUniversity of Engineering & Technology, Lahore, Pakistan.He also has an International Trainer certificate from theNorthern Alberta Institute of Technology, Edmonton,Alberta, Canada.

Michael Albrecht works for SmithNeyrfor in Saudi Arabia as a DrillingProduct Manager. He started his careerwith Norward Energy in 1995,working in Canada and the USA. In2000, Mike took an overseas positionin Kazakhstan as a Safety Supervisor

implementing safe work practices with TCO and ParkerDrilling. He joined Smith Neyrfor in 2004 as a Turbodrillerworking primarily in Canada, and later took a position asa Drilling Product Manager for the Middle East in 2006.Mike has worked in several countries worldwide, includingthe Middle East, and has 14 years of oil field experience.

He is currently based in al-Khobar, Saudi Arabia and hasworked closely with the Saudi Aramco Exploration Groupand the Joint Venture Operators on overseeing TurbineOperations and Sales.

ABSTRACT

Drilling horizontal wells is a common practice for SaudiAramco in most of its oil and gas reservoirs in Saudi Arabianclastic and carbonate fields. The field at hand, with its tworeservoirs, is no exception in regards to these field develop -ment plans. While previously all wells in this field were casedand perforated, during the planning stage for increasingproduction, the question was raised whether an open holehorizontal well completion is feasible over the life of the field(i.e., when taking near-wellbore drawdown and far fieldproduction-induced reservoir depletion into consideration).The direct benefit would be that an open hole completiongreatly reduces the development costs for the 300+ productionwells planned for the field.

A rock mechanics study was undertaken to provide acomprehensive understanding of the wellbore stability of openhole horizontal wells throughout their life span, from drillingthrough production during field development. Two objectivesidentified for the study were: 1) assessment of wellborestability and critical drawdown rates during production toavoid well collapse, and 2) the optimal well deviation,azimuth and required mud weight during drilling to minimizewellbore instability problems. To increase the accuracy of theresults and greatly reduce uncertainty, cores from bothreservoirs were retrieved to provide representative samples ofthe formations of interest. A testing program was undertakento determine the static and dynamic mechanical properties,compressive rock strength, rock failure characteristics andthick wall cylinder strength. The effect of water on rockstrength was tested as well, to evaluate if water encroachmentposes additional risk to the mechanical integrity of theformation. In addition, the required geomechanical model – inparticular in-situ stress field, magnitude and direction – wasdetermined from several data sources: stress-induced wellborefailure analyses (from oriented caliper and wellbore image loganalyses), microfrac testing, direct pore pressure measure -ments, wireline log data, and analysis of the general regionalstress information for the area surrounding the field.

The study showed that an open hole completion is feasiblefor most well azimuths in both reservoirs. Although, it wasdetermined that the tar-bearing intervals of both reservoirs arenot competent enough to be completed open hole due to the

risk of wellbore collapse. The recommendation was thereforeto avoid the tar-bearing intervals and to consider casing thosezones as applicable. The rock strength showed minimal effectas a result of exposure to water; therefore, water flooding willnot be a concern from a wellbore integrity point of view. Afield-specific compressive rock strength-wireline sonic logcorrelation was developed and calibrated with results from thelab tests. The flank wells tolerate more drawdown pressurethan crest wells, due to higher rock strength in the flank.Additionally, it is recommended that the wells be drilled in thedirection of minimum principal horizontal stress (σhmin), tomaximize borehole stability and minimize required mudweights during drilling and completion. The results from thisextensive study were incorporated into Saudi Aramco’sreservoir management decision tree.

INTRODUCTION

Wellbore instability problems are being experienced during thedrilling of horizontal wells in highly stressed formations, suchas shale, unconsolidated sandstone and weak carbonates. Theinstability problems can range from a simple washout to totalcollapse of the hole, and these problems are related to themechanical properties (strength and deformation under stress),the drilling fluids properties, the in-situ stress field, and time-dependent deformation. Open hole completion may bepossible in weak carbonate if the in-situ stress field is notcritical in terms of magnitude and mode (normal, strike-slip orinverse). For example, a rock mechanics study on a shallowcarbonate formation in Saudi Arabia has revealed unconfinedcompressive strengths less than 2,000 pounds per square inch(psi); however, the results of wellbore caliper monitoring as afunction of production time showed no changes in wellboresize, and therefore all horizontal wells were completed openhole1.

Over the past years, drilling extended-reach wells with longopen hole intervals has increased markedly in the industry,and Saudi Aramco has taken a lead role in these activities. Forthe difficult drilling campaigns associated with drilling theselong-reach wells, oil-based mud (OBM) systems have been theindustry choice for difficult drilling. Their application hasbeen typically justified on the basis of borehole stability, fluidloss, filter cake quality, lubricity and temperature stability.


Evaluation of Wellbore Stability duringDrilling and Production of Open HoleHorizontal Wells in a Carbonate Field

Authors: Dr. Hazim H. Abass, Mickey Warlick, Cesar H. Pardo, Mirajuddin R. Khan, Dr. Ashraf M. Al-Tahini, Dr. Dhafer A. Al-Shehri,Dr. Hameed H. Al-Badairy, Yousef M. Al-Shobaili, Dr. Thomas Finkbeiner and Satya Perumalla

Water-based muds (WBM) are attractive replacements from adirect cost point of view. Past efforts to develop improvedWBM for shale drilling have been hampered by a limitedunderstanding of the drilling fluid/shale interactionphenomenon. This limited understanding has resulted indrilling fluids designed with non-optimum properties toprevent the onset of borehole instability.

The structure of the oil field analyzed in this study is aconventional northwest trending asymmetric anticline. Todevelop the field to its target production, Saudi Aramco’sreservoir management team planned to drill a number ofhorizontal wells to ensure maximum reservoir contact (MRC).Because the mechanical integrity of the wellbore for an openhole completion strategy is of critical importance, SaudiAramco decided to have a geomechanics evaluation conductedto understand if and how well integrity can be maximizedthrough utilization of the right mud weights and welldirections, so that stable conditions during drilling andproduction would be guaranteed. The objective was to evaluatethe feasibility of open hole completion; therefore, the wellborestability throughout the life span of the well was the focus ofthe study. Additionally, it is important to optimize the mudweights during drilling to minimize wellbore instabilities, and torecommend optimal well orientations and maximum values fordrawdown and depletion to allow for a stable well throughoutthe production phase. Therefore, the objective of the study wasto combine the knowledge of reservoir and material propertieswith a detailed analysis of the present-day in-situ stress field toassess under what conditions, during drilling and production,mechanical rock failure may occur at the wellbore wall andbecome so severe that it would no longer be manageable.

RESERVOIR CHARACTERIZATION FOR WELLBOREINTEGRITY ANALYSIS

Creating a circular hole and introducing drilling andcompletion fluids to an otherwise stable formation is thereason for a series of phenomena that can result in wellboreinstability, casing collapse, perforation failure and sand/solidsproduction. The circular hole causes a stress concentrationthat extends to a few wellbore diameters away from the hole.This stress concentration, which differs from the far-fieldstresses, could exceed the formation strength, resulting infailure. The circular hole also creates a free surface thatremoves the natural confinement, which can, depending onthe mechanical properties of the formation, reduce formationstrength and trigger inelastic and time-dependent failure.Therefore, a circular hole causes several important effectsaround a wellbore: 1) creation of a stress concentration field,2) removal of the confinement condition, and 3) inelastic andtime-dependent displacement caused by creating a free surface.Additionally, when a wellbore is actively loaded (pressure inthe wellbore is less than the reservoir pressure) or passivelyloaded (pressure in the wellbore is higher than the reservoirpressure), another stress effect could cause wellbore failure.

Wellbore failure that triggers solids production may becompressive, tensile, cohesive or a combination of all three.The compressive failure occurs during drilling where the rockcannot withstand the concentration of hoop stress around thehole. In addition, when cementation materials deteriorate dueto mud filtrate exposure, the problem can be exacerbated. Thecalculation of mud weight to prevent compressive failure willbe presented in this article. Typically, the failed zone isoriented in a specific direction relative to the in-situ stressfield; therefore, the well orientation can be selected tomaximize wellbore stability during drilling and production.

A geomechanics study was initiated to predict wellborestability during drilling, completion and production. The basisfor making successful and accurate predictions lies in theunderstanding of a sound geomechanical model. Theconstituents of the geomechanical model are three principalstresses (vertical stress, maximum principal horizontal stress,and minimum principal horizontal stress), pore pressure andmechanical rock properties. When the horizontal stresses arenot equal (a frequent condition in the Earth’s crust), a stressanisotropy is created, and wellbore instability can bepronounced as wells are direction and deviation sensitive.Pore pressure is another important parameter in thegeomechanical model as most failure criteria depend oneffective stress. When all these parameters are known, ageomechanical model can be created and subsequently utilizedfor evaluation of wellbore stability. In this study, data from 11wells were used to determine the in-situ stress field (magnitudeand direction), and the reservoir pressure. The analyzed datainclude in-situ pore pressure tests, wireline logs (includingelectrical FMI/FMS image logs) and laboratory results fromrock mechanical tests (triaxial compression as well as thickwall cylinder tests). The approach for predicting wellborestability is then based on a comprehensive understanding ofthe present-day geomechanical model of the field, verified andcalibrated against drilling experiences (i.e., indication ofmechanical well instability in wells previously drilled in thefield and target formations). The latter information is acquiredand compiled from drilling and completion reports. Problemsencountered during drilling are classified into differentcategories, such as tight hole, pack off, washing, reaming andmore. Based on drilling experience for a specific mud weightin a given well trajectory, the generated geomechanical modelis verified and calibrated to mechanical failure in the wellbore(stress induced borehole breakouts, hole washouts, etc.) insuch a way that it robustly and accurately predictscompressive and tensile failure around given wellbores.

PORE PRESSURE

Pore pressure within the Earth’s crust plays a vital role inmanaging wellbore stability during drilling and production,governing stress magnitudes (e.g., the fracture gradient,among others). The overall effect of pore pressure changes isinfluenced by the rock behavior, including pore and bulk



respect to depth taken from many wells revealed an over -burden gradient of 1.04 psi/ft at the level of the reservoirs.

MINIMUM HORIZONTAL PRINCIPAL STRESS

Only very limited information on the minimum principalstress (σhmin) was available, since no leakoff tests (LOT) orextended leakoff tests (XLOT) were conducted in thereservoirs. One injectivity test was performed in Reservoir Bat 8,265 ft, and we utilized the maximum pressure reachedfrom this test as a proxy for the least (or minimum) horizontalprincipal stress, with an equivalent gradient of 0.75 psi/ft.

MAXIMUM HORIZONTAL PRINCIPAL STRESS

Similarly to the in-situ stress orientation, interpreted boreholebreakouts from the FMI log were utilized to constrain themagnitude of the maximum principal horizontal stress (i.e.,σHmax). The analyzed breakout width and orientation, as wellas σhmin from the injectivity test and the UCS, were utilized toestimate the magnitude of σHmax. The analysis resulted in anaverage value of 0.97 psi/ft as a lower bound and 1.07 psi/ftas an upper bound in the field. Therefore, the present-day in-situ stress field can be characterized as a transitional normalto strike-slip faulting system, such that σHmax ≥ σv > σhmin.

ROCK MECHANICAL PROPERTIES

For a successful drilling and completion strategy in poorlyconsolidated formations, it is vital to determine themechanical properties of the formation. The followingproperties are needed to provide recommendations onwellbore azimuth, mud weight window during drilling,completion design, and wellbore stability prediction duringproduction: 1) Static and Dynamic Young’s modulus (E)and Poisson’s ratio (v), 2) UCS, 3) Cohesive strength (c), 4)Internal friction angle (ø), and 5) Hollow cylinder strength(HCS). An experimental testing program was initiated toderive some of the parameters listed above. Samples of

compressibility often discussed under stress path response ofreservoir. As pore pressure changes with time during the lifecycle of a field due to production and injection processes,stress magnitudes (including the fracture gradient) changeaccordingly. These production/injection induced stress changesmay influence the stability of a wellbore as well as causecompaction and subsidence on the field scale in some cases.

The pore pressure in the formations of interest, as derivedfrom direct measurements in offset wells, at present isapproximately hydrostatic with no significant overpressuredetected. In Reservoir A, current pore pressure is 3,980 psi,and will be depleted appreciably to 3,000 psi, in 2024 and to2,000 psi in 2035. In Reservoir B, current pore pressure is3,832 psi, and it will be depleted to 3,200 psi in 2024 and to2,500 psi in 2035. The corresponding gradients from thesevalues were used as the current and future pore pressureconditions in the two reservoirs for wellbore stability analysesduring drilling and production.

IN-SITU STRESS ORIENTATION

An available electrical image log (i.e., FMI) for this study fromone well was rigorously calibrated, verified and dynamicallynormalized to provide optimal image quality. The purpose ofthe wellbore image analysis was to identify and characterizestress-induced wellbore failure, such as stress-inducedborehole breakouts and drilling-induced tensile fractures.Wellbore breakouts are enlargements of the wellbore wall,with 180° spacing caused by localized shear failure where thecircumferential hoop stress is most compressive and exceedsthe uniaxial compressive strength (UCS) of the rock. Invertical wells, breakouts always form in the direction of theleast principal horizontal stress (σhmin)2, 3. In deviated wells,however, the position of breakouts is a function of thewellbore trajectory and the stresses acting on the well4.Therefore, when wellbore failures can be detected, theiroccurrence and characteristics (i.e., azimuthal width) can beused to constrain in-situ stress magnitudes, effective rockstrength and stress orientations.

Drilling-induced tensile wall fractures occur where thecircumferential hoop stress may become tensile and exceed thetensile strength of the rock. They also form symmetrically inthe borehole wall 90° from the orientation of the breakouts(i.e., in vertical wells in the direction of the maximum principalhorizontal stress, σHmax)5. Statistical analysis of a wellborefailure indicated a mean value for the orientation of the σHmax

as N25°E with a marginal error of 10º. This estimated azimuthfor σHmax strikes obliquely to major fault trends found in thefield, and it is consistent with the regional stress trend.

OVERBURDEN

The vertical in-situ stress (σv) was derived from bulk densitywireline log data that were acquired from the surface down tothe reservoir levels. Integration of the density data with Fig. 1. Stress-strain curves from a single stage triaxial test.

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Fig. 2. Mohr circles and Coulomb failure line (left) from the samples tested in single stage mode (right) - the resulting rock mechanical parameters are shown in box on top left.

Table 1. A summary of rock-mechanical testing results

Bulk Confining Young's Poisson Peak Friction ShearSample Depth Density Porosity Pressure Modulus Ratio Strength UCS Angle Cohesion Angle

# (ft) (gm/cc) % PSI (PSI) (PSI) (PSI) (Degrees) (PSI) (Degrees)S-02 8,153.3 2.64 2.0 747.9 6.705E+06 0.386 25,466 22,736.8 41.7 5,101.6 65.8S-03 8,153.7 2.65 1.5 1,456.7 7.596E+06 0.333 31,424.5S-04 8,153.8 2.67 0.8 2,944.2 7.133E+06 0.346 36,887.8

LA-07 8,212.4 2.08 15.4 717.9 6.287E+05 0.358 1,861 237.2 22.8 78.9 56.4LA-08 8,213.2 2.12 15.0 1,459 8.776E+05 0.265 3,537.1LA-09 8,213.4 2.10 14.2 2,917.9 9.003E+05 0.324 3,571.2S-06 8,335.9 2.35 11.2 722.6 1.333E+06 0.098 4,041.4 2,462.2 21.8 832.8 55.9S-07 8,336.2 2.31 11.3 1,463 1.308E+06 0.065 5,659.7S-08 8,336.4 2.25 12.5 2,905.9 8.516E+05 0.235 5,085.8S-10 8,369.7 2.48 6.5 735.4 4.152E+06 0.201 10,461 9,038.2 25.9 2,827 58S-11 8,370.1 2.50 5.9 1,458.5 4.970E+06 0.258 13,448.4S-12 8,370.3 2.44 7.7 2,912.9 4.753E+06 0.243 16,254.9

MO-36 8,734.2 1.97 24.3 2,906.3 2.079E+06 0.205 5,509.4 458.8 21.9 155 56MO-26 8,734.7 2.02 15.9 733.1 1.312E+06 0.201 2,028.3MO-27 8,734.9 2.10 15.3 1,455.9 1.798E+06 0.223 3,721.6RM-3D 8,735.2 2.00 16.7 729.4 1.011E+06 0.174 2,125.8 830.3 11.3 340.3 50.7MA-28 8,735.7 2.13 14.5 2,905.6 1.500E+05 0.132 5,111MO-32 8,736.9 2.06 16.7 153.4 4.968E+05 0.500 975.MA-23 8,739.8 2.21 8.4 154.4 7.994E+05 0.366 1,251.3 1,803.9 18.7 646.5 54.4RM-4D 8,742.9 2.40 5.6 2,904.3 2.656E+06 0.472 6,690.7RM-2D 8,743.4 2.37 1.4 1,455.2 2.041E+06 0.312 5,445.6MO-46 8,765.2 2.37 0.1 726 3.127E+06 0.323 7,587.3 15,319.8 42.7 3,357.8 66.3MO-47 8,765.4 2.35 0.1 1,465.1 2.470E+06 0.246 7,789.2MO-48 8,765.8 2.42 0.1 2,909.4 3.276E+06 0.245 12,664.8MO-49 8,807.1 2.93 0.3 724.7 6.807E+06 0.217 19,258.2 15,298 42.7 3,346.1 66.4MO-50 8,807.2 2.93 0.5 1,454.5 7.105E+06 0.238 22,638MO-51 8,807.4 2.91 0.8 2,905.4 9.855E+06 0.075 30,523.5


microscope (ESEM) and energy dispersive X-ray (EDX) tests,to understand the nature of these samples. The resultsrevealed that high-sulfur tar was mainly found between theoolites, and no tar was found in the micropores of CaCO3

within the oolites, Fig. 4. The tar seems to be likecementation materials to the oolitic groups; thereby reducingthe mechanical strength of the formation. Therefore, the tar-bearing zones are not competent enough to be completedopen hole due to the risk of wellbore collapse. Therecommendation is to avoid as much as possible the tar-bearing intervals or consider casing those zones as applicable.

ROCK-STRENGTH MODEL

It is important to characterize an entire formation in termsof its compressive rock strength to evaluate wellbore stabilityduring drilling, completion and production. Figure 5 showslab result correlations between the UCS and porosity, or theUCS and the inverse of compressional velocity. Since coreplugs are generally obtained from a limited portion of thereservoir only, it is imperative to establish empiricalcorrelations between rock properties (as determined in thelaboratory) and log data to obtain tools for formationstrength characterization along the entire reservoir in a givenwellbore. Sonic log data and the UCS lab results wereutilized to obtain a transform for rock strength, whichprovides a continuous rock strength profile of the reservoirsection, Fig. 6. The following transforms were the basicrelations for the functions appearing in Fig. 6:

UCS = 366,842 e(-0.0624Δt) (Reservoir A)

UCS = 20.244 (Δt)2 – 3302 (Δt) +135,741 (Reservoir B)

The units for UCS are in psi and Δt (compressional sonicinterval transit time) is in μsec/ft. Although the strength modelis derived based on one well, it can be applied to other areas

1½” diameter by 3” length were plugged horizontally froma full core (4” diameter) and tested in a single andmultistage fashion. Confining pressures for these tests wereselected to simulate the stress and pressure conditions inthe vicinity of the wellbore (i.e., 5 MPa, 10 MPa and 15MPa). The multistage procedure implies that an earlierloading cycle is unloaded when the rock sampleapproaches failure at a given confining pressure and thesame sample is reloaded under the subsequent higherconfining pressure.

Triaxial Compression Tests

Weak samples were tested in a single stage, conducted onthree plugs, Fig. 1. The triaxial testing results were modeledby Mohr-Coulomb failure criterion. This criterion postulatesthat failure occurs when shear stress at a given plane reaches acritical value related to the formation frictional resistance, andis given by:

(1)

Equation 1 shows three components: cohesion (c), effectivenormal stress (σn) and friction (tan ø). Shear failure breaks therock along shear planes. Equation 1 may be described interms of the principal stresses as follows:

(2)

The factors UCS and φ are coefficients for the linearizationand should be determined experimentally. The failure envelopeis determined from many Mohr circles. The envelope of thesecircles represents the basis of this failure criterion, Fig. 2. Asummary of the rock mechanical testing results of coresamples taken from both reservoirs are shown in Table 1.

THICK WALL CYLINDER (TWC) TESTING

Thick wall cylinder tests were performed on core samples of1½” diameter with a 0.5” diameter hole drilled exactly in thecenter. The axial and confining stresses are simul taneouslyincreased during the test (i.e., the sample is loadedhydrostatically). The axial stress, confining pressure, axialstrain and radial strain are monitored during the test. Loadingcontinues until complete sample failure occurs or themaximum loading stress (governed by the loading frame) isreached. The thick-walled cylinder test provides a simulatedcondition of the near wellbore formation being stressed as thenear wellbore reservoir pressure is decreased. The resultingelastic/plastic deformations around the wellbore as a functionof the effective-stress increase can be modeled to determinethe critical reservoir pressure at which wellbore failure isinitiated. Figure 3 shows selective thick wall cylinder tests.

The lowest failure stress of about 4,000 psi was observedin tar-bearing samples, as shown in the top right graph ofFig. 3, which depicts a collapse of the inner hole. Therefore,two tests were performed: environmental scanning electron Fig. 3. Four thick wall cylinder tests performed on selective samples.

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within the reservoir. Therefore, the sonic log is a tool that canbe used as a proxy for rock strength at any location. The log-based strength correlations can be statistically evaluated tofind average wells as minimum/maximum values anddistribution functions of rock strength. Based on thedeveloped correlations, it was found that Reservoir B appearsrelatively weaker than Reservoir A. Furthermore, there is atrend of increasing rock strength from the crest to the flanks.Reservoir B exhibits narrow P10 (10th percentile) and P50(50th percentile) ranges 2,000 psi to 3,000 psi and 2,500 psi to4,950 psi, respectively, while the same range for Reservoir A is2,500 psi to 4,500 psi and 3,750 psi to 7,700 psi. Figure 7shows the UCS distribution functions across Reservoirs A andB as derived using sonic log velocities and lab strength data.Great variability depicting rather strong (UCS >10,000 psi) aswell as rather weak (UCS < 2,000 psi) intervals are apparent.Also, Reservoir A appears generally stronger than Reservoir B.

WELLBORE STABILITY DURING DRILLING(UNDEPLETED AS WELL AS DEPLETED CONDITIONS)

The geomechanical model previously developed and discussedwas utilized as a basis to predict minimum required mudweights during drilling and completion of the reservoir


Fig. 4. Tar-bearing sample showing the dark phase, which is tar between the oolites.

Fig. 5. Lab-data correlations of UCS as a function of porosity (top), and 1/Vp(bottom).

Rock Strength Correlation - UCS-Porosity

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Fig. 6. Continuous UCS profiles for Reservoir A (left) and Reservoir B (right).


with a high tendency for failure, while cool colors show a lowfailure tendency. These diagrams are constructed at an averagedepth for Reservoir A. Figure 8 also shows an example of thisdiagram assuming average rock strength, UCS = 8,000 psi, forthe initial Reservoir A pressure of 3,980 psi and at a depletedcondition of 3,000 psi. Generally, highly deviated andhorizontal wells oriented along σHmax (i.e., N25°E) requirehigher mud weights than those drilled normal to σhmin (i.e.,N115°E). In addition, wells deviated up to 30° can be drilledin any direction with more or less the same mud weight (i.e.,less sensitive to well azimuth). The directions of horizontalwells with special focus are shown by the white circles: N25°E,N55°E, N70°E, N85°E and N115°E. The color scale in thediagrams was set so that it spans the same range of mudweights to better compare the changes in mud weights as aresult of production. We also indicate the direction of σHmax.

WELLBORE STABILITY DURING PRODUCTION

If the reservoir pressure is reduced in response to depletion,the effective stress within the rock formation increasesaccording to the effective stress concept. A Mohr-Coulombmaterial with strain hardening model was developed to beused in the finite element modeling. Triaxial tests thatexhibited shear failure without compaction, characterized byan increase then a decrease in volumetric strain, were selectedto establish the material model which describes the entireloading part of a sample in the elastic and plastic domain untilthe peak stress at failure.

This material model was then used to simulate the thickwall cylinder tests to construct a generic material model thatdescribes the weakest parts of the reservoir. The empirical

formation under present-day pore pressure conditions. Weconducted the wellbore stability analysis also for depletedpressure conditions assuming a depletion developmentscenario. The plan predicts a decrease of Reservoir A’s pore-pressure from an average current value of ~3,980 psi to3,000 psi in 2024 (ΔP = 980 psi) in response to production(as discussed above).

As reservoir pressure declines due to production, the totalhorizontal stresses decline as well. Commonly, the stress path(i.e., change of stress with change of pore pressure) in a givenreservoir can be established with repeated extended leakoff orminifrac tests. Since these data were not available, wecalculated the stress changes by assuming poroelastic reservoirbehavior. This poroelastic model is two-dimensional andassumes a relatively flat, extensive (i.e., length >> width)reservoir with constant overburden stress. For the horizontalprincipal stress changes, we consider coupling between porepressure and total stress depending upon the value of Poisson’sratio as well as Biot’s coefficient. This results in ΔS/ΔP = 0.67for Poisson’s ratio of 0.25 and Biot’s coefficient of 1.0.

MINIMUM MUD WEIGHT PREDICTIONS

For the stability analysis, we constructed lower hemispherestereographic projections, Fig. 8, that enables the prediction ofminimum required mud weights for wells of arbitrarydeviation and orientation to maintain well integrity at aspecific depth. The colors indicate failure tendency in terms ofrequired mud weights to restrict wellbore failure to a criticalbreakout width (i.e., 90° for vertical wells and 30° for thehorizontal wells; for intermediate hole inclinations, it is linearlyinterpolated). Warm colors indicate orientations and deviations

Fig. 7. UCS distribution functions across Reservoir A (left) and Reservoir B (right).

relationship between Young’s Modulus and UCS was obtainedfrom the results of lab tests and incorporated in the finiteelement model to evaluate rock plastic strains under differentpressure drawdown scenarios. A critical total plastic strainwas considered as a criterion to evaluate wellbore integrityunder a given depletion mode. A critical total plastic strainwas determined and calibrated with the thick wall cylindertests. The failure criterion derived indicated that failureinitiation occurs at a plastic strain of 15 millistrain, andcomplete hole failure (i.e., collapse) results when the plasticstrain is 20 millistrain. The P10 rock strength value wasselected in the finite element simulation, which is 4,500 psi forReservoir A and 2,000 psi (Crest well) to 3,000 psi (Flankwells) for Reservoir B. The simulations were conductedutilizing present-day pore pressure values as well as thosepredicted for 2024 and in 2035. We ran simulations for wellazimuths parallel to σHmax, and σhmin, as well as intermediateazimuths between σHmax and σhmin directions of N85°E,N70°E and N55°E. Furthermore, we investigated threedifferent pore-pressure levels of Reservoir A: 3,980 psi(present day), 3,000 psi and 2,000 psi.

In general, we found that the most favorable wellorientation under any drawdown and depletion condition isN115°E, which is parallel to σhmin and the least favorable wellorientation under any drawdown and depletion condition isN25°E, which is parallel to σHmax.

For horizontal wells parallel N115°E (in direction of σhmin),we find:

• At present-day reservoir pressures, horizontal wellsparallel to N115°E (in direction σhmin) are predicted tohave solids-free production and a stable borehole evenat 2,500 psi drawdown.

• When reservoir pressure reaches 3,000 psi, horizontalwells parallel to N115°E (in direction of σhmin) willproduce solids free if drawdown is limited to 900 psi;borehole collapse, however, is not expected unless thedrawdown exceeds 2,500 psi.

• When reservoir pressure reaches 2,000 psi, horizontalwells parallel to N115°E (in direction of σhmin) arepredicted to produce some solids at any drawdown;borehole collapse, however, is not expected unless thedrawdown exceeds 800 psi.

For horizontal wells with azimuth N70°E - N250°E, we find:

• At present-day reservoir pressures, horizontal wells parallelto N70°E are predicted to produce solids free if drawdownis limited to 1,875 psi; borehole collapse, however, is notexpected unless drawdown exceeds 2,500 psi.

• When reservoir pressure reaches 3,000 psi, horizontalwells parallel to N70°E are predicted to produce somesolids at any drawdown; borehole collapse, however, isnot expected unless drawdown exceeds 1,850 psi.


Fig. 8. Lower hemispheric projection showing required mud weights to prevent excessive wellbore failure and collapse for wellbores of arbitrary deviation and orientationdrilled into Reservoir A with an assumed rock strength of UCS = 8,000 psi at an initial condition of reservoir pressure = 3,980 psi (left), and at a depleted condition ofreservoir pressure = 3,000 psi.


• At present-day reservoir pressures, horizontal wellsparallel to N25°E (in direction of σHmax) are predictedto produce solids free if the drawdown is limited to 900psi; borehole collapse, however, is not expected unlessthe drawdown exceeds 2,500 psi.

• When reservoir pressure reaches 3,000 psi, horizontalwells parallel to N25°E azimuth (in direction of σHmax)are predicted to produce some solids at any drawdown;wellbore collapse, however, is not expected unless thedrawdown exceeds 900 psi.

• When reservoir pressure reaches 2,000 psi, horizontalwells with N25°E (parallel to σHmax) azimuth arepredicted to collapse at any drawdown.

Figure 9 shows the results as highlighted above in terms ofplastic strain vs. drawdown for the different pore pressureconditions and well azimuths.

CONCLUSIONS

1. The geomechanical model for the Reservoir A field is atransition between normal and strike-slip faultingsystems (σHmax ≥ σv > σhmin), with vertical stress of ~150pcf - 151 pcf, minimum horizontal stress (σhmin)estimated to be ~106 pcf, maximum horizontal stressestimated to be ~145 pcf - 155 pcf and hydrostatic porepressure level (64.4 pcf) at reservoir level. A rockstrength correlation between UCS and sonic velocity hasbeen established.

2. The mud weight required to prevent breakout generationand maintain wellbore stability during drilling wasdetermined, as it is important to obtain a gauged holeduring drilling for a maximum wellbore stability duringproduction. Minimum mud weights required to drill ahorizontal well in Reservoir A at initial reservoir pressureare 64 pcf - 65 pcf for a well parallel to σhmin directionand 68 pcf - 70 pcf for a well parallel to σHmax direction.These mud weights will proportionally reduce when thereservoir is depleted to 3,000 psi. The minimum mudweights required to drill a horizontal well in depletedconditions are 56 pcf - 57 pcf for a well parallel to σhmin

direction and 61 pcf - 62 pcf for a well parallel to σHmax

direction.

3. The tar-bearing zones are not competent enough to becompleted open hole due to the risk of wellbore collapse.The recommendation is to avoid as much as possible anytar-bearing intervals or consider casing those zones asapplicable.

4. Open hole completion is possible in non-tar zonesand the most favorable well azimuth is N115°E,which is the direction of σhmin. A horizontal welldrilled at this direction will be stable even at 2,500psi drawdown at present-day pore pressure conditionsin Reservoir A.

• When reservoir pressure reaches 2,000 psi, horizontalwells with N70°E azimuth are predicted to collapse atany drawdown.

Following are results for horizontal wells with azimuthN25°E - N205°E (in direction of σHmax), the least favorablewell orientation under any drawdown and depletion:

Fig. 9. Plastic strain vs. drawdown for five different well azimuths considered inthis project (shown with different colors). The orange and red horizontal lines,respectively, represent the critical plastic strain values for which solid productioninitiates and becomes severe (i.e., hole is predicted to collapse). (a) Present-day porepressure of 3,980 psi, (b) Reservoir pressure of 3,000 psi, (c) Reservoir pressure of2,000 psi.

ACKNOWLEDGMENTS

The authors wish to thank Saudi Aramco management fortheir support and permission to present the informationcontained in this article.

REFERENCES

1. Salamy, S.P., Faddagh, H.A., Ajmi, A.M., Lauten, W.T. andMubarak, H.K.: “Methodology Implemented in Assessingand Monitoring Hole Stability Concerns in Open HoleHorizontal Wellbores in Carbonate Reservoirs,” SPE paper56508, presented at the SPE Annual Technical Conferenceand Exhibition, Houston, Texas, October 3-6, 1999.

2. Zoback, M.D., Moos, D., Mastin, L. and Anderson, R.N.:“Wellbore Breakouts and In-Situ Stress,” J. Geophys. Res.,Vol. 90, 1985, pp. 5,523-5,530.

3. Moos, D. and Zoback, M.D.: “Utilization of Observationsof Wellbore Failure to Constrain the Orientation andMagnitude of Crustal Stresses: Application to Continental,Deep Sea Drilling Project and Ocean Drilling ProgramBoreholes,” J. Geophys. Res., Vol. 95, 1990, pp. 9,305-9,325.

4. Peska, P. and Zoback, M.D.: “Compressive and TensileFailure of Inclined Wellbores and Determination of In-SituStress and Rock Strength,” J. Geophys. Res., Vol. 100, No.7, 1995, pp. 12,791-12,811.

5. Ahmed, M.S., Finkbeiner, T. and Kannan, A.: “UsingGeomechanics to Optimize Field Development Strategy ofDeep Gas Reservoirs in Saudi Arabia,” SPE paper 110965,presented at the SPE Saudi Arabia Technical Symposium,Dhahran, Saudi Arabia, 2007.


BIOGRAPHIES

Dr. Hazim H. Abass is a PetroleumEngineering Consultant at theExploration and PetroleumEngineering Center - AdvancedResearch Center (EXPEC ARC) ofSaudi Aramco. His research area ofinterest is applied rock mechanics in

petroleum engineering, especially in hydraulic fracturing,wellbore stability, sand production, perforation and stressdependent reservoirs.

Before joining Saudi Aramco in 2001, he worked for 2years at the North Petroleum Company in Iraq, 1 year at theColorado School of Mines, 9 years at the HalliburtonR&DC in Duncan, OK and 5 years as Halliburton’srepresentative to the PDVSA R&DC in Los Teques,Venezuela. Hazim holds nine U.S. patents, has authoredmore than 35 technical papers and contributed to threeindustrial books. He is a member and the Technical Editorof the Society of Petroleum Engineer’s (SPE) Production &Facilities and is a member of the International Society forRock Mechanics (ISRM). Hazim received the 2008 SPEMiddle East Regional Award of Production and Completion.

In 1977, Hazim received a B.S. degree in PetroleumEngineering from the University of Baghdad, Baghdad, Iraq.He received his M.S. and Ph.D. degrees in 1987 in PetroleumEngineering from the Colorado School of Mines, Golden, CO.

Mickey Warlick is a PetroleumEngineering Specialist with the ManifaReservoir Management Division and hasbeen with Saudi Aramco for 7 years. In1981, he received his B.S. in PetroleumEngineering from the New MexicoInstitute of Mining and Technology at

Socorro, NM. Mickey joined Chevron USA Inc., and beganwork as a Reservoir Engineer in the Permian Basin located inwest Texas and eastern New Mexico. There, he worked ondiverse reservoirs ranging from shallow 2,000 ft oil reservoirsto 30,000 ft deep gas reservoirs. Mickey gained experience inworking on primary, secondary and even CO2 tertiaryprocesses. He then moved to the Over Thrust area ofWyoming where he gained firsthand experience in dealingwith 20% H2S gas reservoirs that required utmost safety indrilling and workover operations. Later Mickey moved on toLa Habra, CA where he worked in Chevron’s internationaloperations developing and deploying new field technologies.

Just before his move to Saudi Arabia, Mickey transferredto Houston, TX where he worked as a Reservoir SimulationEngineer in Chevron’s International Reservoir Simulationdepartment. While in Houston, he earned his M.S. degree inPetroleum Engineering from the University of Houston,Houston, TX in 2001. Mickey joined Saudi Aramco in 2002,working as a Reservoir Engineer in the Zuluf field. WhenSaudi Aramco decided to bring the Manifa field on as one ofits major increments, he was transferred there and iscurrently Team Leader for the Manifa reservoir of the Manifafield development.


Cesar H. Pardo has 22 years ofexperience with E&P companies. Hejoined Saudi Aramco in 2006 andworked for 1 year for the GasReservoir Management Department(GRMD) as a Senior ReservoirEngineer. In April 2007 Cesar was

moved to the Manifa Reservoir Management Division(MRMD) where he currently works as a PetroleumEngineer Specialist. In 1987 he began working at Ecopetrol(the Colombian state company) where he worked for 4years in drilling, workover and production technologyengineering.

In 1990 Cesar joined Shell Colombia (Hocol) as aWorkover Engineer. In 1992 he was promoted to aProduction Technology Engineer and successfully designedand implemented a fracturing campaign for 30 producerwells and an ESP and gas lift campaign for over 70 wells.In 1996 Cesar was promoted to a Reservoir Engineer,working in Classical Reservoir Engineering and NumericalReservoir Simulation with Eclipse, and he performed anOFM study, identifying new infill drilling and workoveropportunities. In 2002 he was promoted to a SeniorReservoir Engineer and given the additional responsibilityas a Team Leader (Asset Manager Deputy), he preparedand coordinated the Field Development Plan (FDP) for aheavy oil field. In 2004 Cesar was promoted to ReservoirEngineering Network Leader for the whole company inColombia, he coordinated and prepared the new Hocolbooks for forecast and reserves, coordinated calculationprocedures and coordinated the annual reserves review andauditing for 2 years.

Cesar received his B.S. degree in Petroleum Engineeringfrom the Universidad de America, Bogotá, Colombia.

Mirajuddin R. Khan is a Geologistworking in the Exploration andPetroleum Engineering Center -Advanced Research Center (EXPECARC). Since joining Saudi Aramco in1991, he has been serving as the SeniorRock Mechanics Laboratory

Experimentalist.Mirajuddin received his B.S. degree in 1984 and his M.S.

degree in 1985, both in Petroleum Geology from theUniversity of Karachi, Karachi, Pakistan. His interests arerock mechanics’ applications in petroleum engineering.Mirajuddin is a member of the Society of PetroleumEngineers (SPE) and has published several technical papers.

Before joining Saudi Aramco, Mirajuddin worked asTeaching Assistant for 1 year and then received a ResearchScholarship to work as a Research Scholar for 2 years atthe University of Karachi.

His awards include the 2004 Recognition Award of theEngineering & Operations Services of Saudi Aramco.

Dr. Ashraf M. Al-Tahini is a SeniorPetroleum Engineer at the Explorationand Petroleum Engineering Center -Advanced Research Center (EXPECARC) of Saudi Aramco. His areas ofinterest include geomechanics and rockphysics, as he is currently involved in

leading several vital projects in the area of fracturing andsand control.

In 1996, Ashraf received his B.S. degree in ChemicalEngineering from King Fahd University of Petroleum andMinerals (KFUPM), Dhahran, Saudi Arabia. He receivedhis M.S. degree in 2003 and his Ph.D. degree in 2007, bothin Petroleum and Geological Engineering, from theUniversity of Oklahoma, Norman, OK.

During the 12 years of his career and education, he haspresented and published many technical papers. Ashraf hasalso received many awards, including the Society ofPetroleum Engineers (SPE) paper mention award in 2008for the Reservoir Geology and Geophysics Session, thesecond place award for the SPE’s U.S. Rocky MountainMid Continent Ph.D. paper contest in 2004 and theUniversity of Oklahoma Rock Mechanics Award for 2003and 2006. In 2001, he received the best paper andpresentation award during the Saudi Aramco TechnicalExchange Conference in Dhahran.

Ashraf was the Chairman of the 2009 SPE Saudi ArabiaSection Technical Symposium and Exhibition and currentlyhe is the Chairperson of the SPE Saudi Arabia Section. Heis a member of SPE, the Society of Exploration andGeophysics and the American Rock Mechanics Association.

Dr. Dhafer A. Al-Shehri is currentlythe Manifa Subsurface Team Leaderwith Northern Area ReservoirManagement. Since joining SaudiAramco in 1996, he has worked as anEngineer, an Engineering Supervisor,and General Supervisor for Drilling &

Workover Engineering, Reservoir Management andProduction Engineering. Dhafer also acted as the ChiefTechnologist, Drilling Technology Team, Exploration andPetroleum Engineering Center - Advanced Research Center(EXPEC ARC).

Dhafer holds B.S. and M.S. degrees from King FahdUniversity of Petroleum and Minerals (KFUPM), Dhahran,Saudi Arabia, and a Ph.D. from Texas A&M University,College Station, TX, all in Petroleum Engineering.

Prior to joining the company, he was a PetroleumEngineering professor at KFUPM. As an active member ofthe Society of Petroleum Engineers (SPE), he has authoredmany technical papers on various topics and chaired thelocal 1998 SPE Technical Symposium.


Dr. Hameed H. Al-Badairy is a SeniorLaboratory Scientist at the Research &Development Center (R&DC) of SaudiAramco. He received his Ph.D. degreein Materials Science and Engineeringfrom Liverpool University, Liverpool,UK. Hameed has over 15 years of

academic and industrial experience in the fields of materialsscience and electron microscopy. Prior to joining SaudiAramco he worked for 13 years as a Senior ResearchAssociate at the Department of Materials Science andEngineering, Liverpool University.

Hameed has published more than 60 technical papersand is a member of the National Association of CorrosionEngineering (NACE), Institute of Materials, Minerals andMining (IOM3), North West & Liverpool EngineeringSociety and the Technical Committee of the 13th MiddleEast Corrosion Conference and Exhibition (13MECC). Hehas presented his work at over 30 national andinternational conferences and has been an invited keynotespeaker in four international conferences.

Yousef M. Al-Shobaili is currently theNorthern Onshore Fields GroupLeader at the ReservoirCharacterization Department. Hejoined Saudi Aramco in 1994 afterreceiving his B.S. degree in PetroleumGeology and Sedimentology from King

AbdulAziz University, Jiddah, Saudi Arabia. During hiscareer he has worked in several disciplines of theExploration and Petroleum Engineering organizations.

Yousef’s experience covers several reservoir aspects,including reservoir evaluation and assessment, reservoirmanagement and engineering assessment, petrophysicalintegration, reserves estimation and assessment, identifyingnew hydrocarbon from old fields, drilling operations andwell planning, reservoir description and geomechanics andwellbore stability, log analysis and interpretation, and coredescription and integration. He has also trained severalsummer students, geologists, geophysicists and reservoirengineers, and he developed an in-house log interpretationand petroleum geology training course.

Yousef has authored and co-authored 18 technicalpapers in reservoir evaluation, reservoir description,geosteering, rock mechanics, reservoir management anddynamics, and log/core petrophysics. He is the founder andthe first president of the Saudi Petrophysical Society (SPS).

Yousef attended and passed an intensive six monthpetrophysical and log evaluation Schlumberger program.He was the first worldwide non-Schlumberger employee toever join this program.

Dr. Thomas Finkbeiner is the RegionalTechnical Advisor (EAME) forGeoMechanics International (GMI).He began work there as a specialist inreservoir geomechanics and aconsultant for the petroleum industryin wellbore stability and in-situ stress.

In 2001, Thomas was assigned to the Middle East, India,and Pakistan as Director to develop, coordinate andmanage GMI’s services to regional operators and clients. Inthe summer of 2004, Thomas relocated to Dubai, U.A.E.and opened GMI’s regional office to run all Europe, Africaand Middle East operations.

In 1994, Thomas received his M.S. degree in Geophysics,and in 1998, he received his Ph.D. degree, also inGeophysics, both from Stanford University, Stanford, CAunder the supervision of Prof. Mark Zoback (a renownedexpert in geo- and rock mechanics).

He has over 10 years of industry experience ingeomechanics and related applications, such as wellborestability during drilling and production, fluid migrationand more.

Satya Perumalla is a SeniorGeomechanics Specialist, working withGeoMechanics International (GMI)since 2007, and has diverse experiencein making connections betweengeomechanics and drilling problems.

He has over 12 years of experienceworking in the oil and gas industry as a Consultant,working at various levels, supporting well engineering andsub-surface interests of various operators, i.e., Shell, BGand Total, etc., in the Middle East, Africa and India.

Satya received his M.S. degree in Applied Geology fromthe Indian Institute of Technology, Roorkee, India.

ABSTRACT

This article summarizes the results from the deployment of amultistage completion and acid fracturing treatment in thefirst field trial conducted in a Saudi Arabian gas producer. Themain objective of the field trial was to ascertain the effec -tiveness of this state-of-the-art technology in properlystimulating long horizontal gas producers, and therefore use itto help severely damaged or underperforming wells achievetheir maximum potential. The secondary objective was toevaluate the ability to connect the main Khuff-C producingzones through hydraulic fracturing, and therefore ascertain theviability of this technology as a potential alternative for dual-lateral completions in certain parts of the field.

Drilling problems necessitated the reduction of the totalhorizontal well from the originally planned 5,000 ft to a finallength of 3,835 ft. Moreover, mechanical problems en -countered while setting the multistage completion reduced thetotal horizontal length open to flow to 1,440 ft only, leaving2,394 ft isolated and unable to flow. As a result, the numberof fracture stages originally planned at six had to be reducedto only three, but stimulation operations were implementedtrouble-free with a good number of lessons learned that willbe applied in future applications of the technology.Nevertheless, the initial performance of the well comparesfavorably with that of two other non-stimulated horizontalgas producers with better reservoir quality and more reservoircontact, a clear indication of the successful stimulation effectachieved with the job.

This technology offers significant potential to improve theproductivity of underperforming horizontal producers andhelp them achieve their maximum potential.

BACKGROUND

The ability to effectively stimulate underperforming orseverely damaged horizontal gas producers has becomehighly important, considering that a significant number ofexisting horizontal producers fit into this category. As thenumber of horizontal gas producers will continue toincrease in the future, it is imperative to maximize wellproductivity through the implementation of effectivecompletions and technologies. To that effect, the GasProduction Engineering Department (GPED) recommended

and worked in partnership with the Gas ReservoirManagement Department (GRMD) to field test a new state-of-the-art completion technology, named multistage1-6, asthe best available option to ensure effective stimulation ofthe entire horizontal length in wells whose performance isbelow expectations for one reason or another. Thistechnology offers the ability to selectively stimulate zones,and the possibility of replacing dual-lateral completions incertain areas of the field where connecting two pay zonesmay be possible through hydraulic fracturing.

The multistage completion technology provides the abilityto perform multiple fracture treatments, targeting differentzones in an open hole completion in one single operation.Setting a multistage completion is similar to setting a liner, soopen hole packers are run on conventional casing to segmentthe reservoir with hydraulically activated sleeves isolating thefrac ports placed between each set of packers. Duringfracturing operations, balls are dropped from the surface toshift the sliding sleeves, open the frac ports, and isolatepreviously fractured stages.

Gas producer Well-MSX was the first pilot well selected totest this new technology. The well was originally planned as adual-lateral completion targeting two producing zones, so oneof the objectives of the pilot test was to determine thefeasibility of connecting the two zones through a hydraulicfracture treatment. The other key objective was to increase thewell productivity in comparison to a non-stimulatedcondition. If proven successful in reducing the number ofdual-lateral completions in certain areas of the field, the newtechnology would result in significant drilling cost savings byreducing the drilling time. Drilling Well-MSX as a dual-lateralcompletion would have required approximately 120 rig days.Instead, the well was drilled as a single lateral and set with amultistage completion in 76 rig days, thereby reducing thetotal well cost by approximately $1.2 million ($41 K/day),including the cost of the new completion.

This article evaluates the initial post-stimulation per -formance of the well in comparison with the initialperformance of offset horizontal producers with similarreservoir properties. Long-term production key performanceindicators and well performance will be closely monitoredonce the well is tied-in to the gas plant so that properconclusions and way forward recommendations can be issued.


The Use of Multistage New Technology toComplete and Stimulate Horizontal Wells:Field Case

Authors: Hassan M. Al-Hussain, J. Ricardo Solares, Hamad M. Al-Marri and Carlos A. Franco

DRILLING AND COMPLETION HISTORY

The original plan was to drill Well-MSX with a 5,000 ft singlelateral in the Khuff-C reservoir, but because of excessive torquenearing the limit of the bottom-hole assembly (BHA)connections, the drilling engineering department decided tostop drilling short of the target depth. Therefore, the well wasdrilled to a total depth (TD) of 16,385 ft measured depth(MD) and a total horizontal length of 3,835 ft. While runningthe multistage completion, the assembly became stuck andbacked off at 14,048 ft, approximately 2,337 ft short of thetarget depth. Then the assembly parted at the setting tooldepth of 9,144 ft during attempts to free it up. The setting toolwas successfully fished, but it was not possible to dislodge theassembly, so the decision was made to set all eight packers attheir present depth and complete the well. Therefore, the wellwas left with the 2,394 ft bottom drilled section inaccessibleand unable to flow to the wellbore, and with onlyapproximately 1,440 ft of net horizontal reservoir contact.There are plans in place to either perforate the bottommostpup joint, or mill out the bullet nose re-entry guide of themultistage completion to gain access to the 2,394 ft ofcurrently inaccessible open hole net pay section, to increase thewell productivity even further. Figure 1 shows the finalconfiguration of the well and the points chosen to perform theacid frac stimulation through the completed lateral section.

STIMULATION TREATMENT

Due to the problems encountered during the completionoperations, the number of acid fracturing stages had to bereduced from the original six planned to only three. The firstfrac port, at a depth of 13,978 ft, was opened ahead of thetreatment by pressuring up the completion to 4,000 psi, andthen a step rate injection test was performed ahead of the firstfrac stage for calibration and fracture parameters estimationpurposes. The bottom-hole formation breakdown pressurewas estimated at 8,706 psig and the closure pressure at 7,507psig. The first stage fracture treatment was then successfullybullheaded down the tubing at a maximum rate of 94 barrelsper minute (BPM) and a maximum treating pressure of11,700 psig. A total of 167,000 gal of treatment fluids,including acid and pad, were pumped during this stage.

The second frac port, at a depth of 13,470 ft, was openedahead of the treatment by dropping a 2½” ball and pressuringup the tubing to 3,600 psi. The second stage fracture treatmentwas then successfully bullheaded down the tubing at amaximum rate of 108 BPM and a maximum treating pressureof 11,579 psig. A total of 194,000 gal of treatment fluids werepumped during this stage. The third and final stage waspumped through the frac port at a depth of 12,655 ft with atotal fluid volume of 243,222 gal. All three stages werepumped with three alternating stages of borate cross-linked geland 28% hydrochloric (HCl) emulsified acid, followed byleakoff control acid, adopting the same methodologysuccessfully used in stimulation of vertical producers. Figures 2through 4 show the pumping schedule performance monitoredduring each one of the three acid frac stages.

PRODUCTION PERFORMANCE POST ACID FRACSTIMULATION

The well was opened shortly after the stimulation treatment atan initial 16⁄64” choke setting, then slowly opened up to amaximum 92⁄64” choke setting over a 54 hour flow period. Themaximum gas rate recorded was 67 million standard cubicfeet per day (MMscfd) at a flowing wellhead pressure (FWHP)of 1,980 psig. The well was then flowed at two other choke


Fig. 2. Pumping schedule performance for first acid frac stage at 13,978 ft. Fig. 3. Pumping schedule performance for second acid frac stage at 13,470 ft.

Fig. 1. Final well completion after multistage was run in the hole.


lateral non-stimulated offset gas producer, and Well-NMS2, asingle lateral non-stimulated gas producer which exhibitedsimilar productivity to Well-MSX during its flow back period.The two horizontal wells were selected for comparisonpurposes because they were two of the highest producers inthe field, and the vertical well was also one of the highestvertical producers.

A reservoir quality comparison was conducted first in aneffort to normalize and correlate well performance withreservoir conductivity (Kh). Figure 6 shows a permeabilitydistribution comparison between Well-NMS1, Well-NMS2and Well-MSX. The Figure also shows the highest averagepermeability distribution in Well-NMS1 throughout most ofthe horizontal section; Well-NMS2 shows the second highestand Well-MSX the lowest. Figure 7 shows a porositydistribution comparison between the same gas producer wells.The Figure also shows the highest average porosity distri -bution in Well-NMS2 throughout most of the horizontalsection; Well-NMS1 shows the second highest, and Well-MSXthe lowest. Finally, Fig. 8 shows a comparison of net intervalsopen to flow in the three compared horizontal wells. Well-NMS1 is a dual-lateral with a maximum combined horizontalreservoir contact of 9,298 ft, Well-NMS2 is a single lateralwith a maximum horizontal reservoir contact of 4,546 ft, and

settings to obtain data to build an inflow performance curve,and it flowed at 42 MMscfd at a FWHP of 2,930 psig on a 1”choke setting, and at 21 MMscfd at a FWHP of 3,400 on a42⁄64” choke setting. Figure 5 shows the well performanceduring the flow back period.

The performance of the well was compared with that oftwo other non-stimulated horizontal gas producers withsimilar reservoir quality characteristics to ascertain theeffectiveness of the stimulation treatment in Well-MSX.Therefore, a comparison was made with Well-NMS1, a dual-

Fig. 4. Pumping schedule performance for third acid frac stage at 12,655 ft.

Fig. 5. Gas production performance monitored during 54 hours of cleaning up period.

0

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Fig. 8. Radial displacement comparison.

Fig. 6. Permeability comparison against high gas producer condensate wells.

Fig. 7. Porosity comparison against high gas producer condensate wells.

Well-MSX is a single lateral with a maximum effectivehorizontal reservoir contact of only 1,440 ft, because theother 2,394 ft horizontal interval is temporarily isolated andunable to flow. Therefore, the reservoir contact open to flowin Well-NMS1 is six times higher than in Well-MSX, andthree times higher in Well-NMS2.

From the above data it was possible to calculate the Kh forthe three comparison wells, Table 1.

The data shows that the Well-NMS2 reservoir conductivity isfive times higher than the conductivity of the zone open to flowin Well-MSX, whereas the conductivity of the Well-NMS1combined laterals is 7.5 times higher than the Well-MSXconductivity. Consequently, based on total reservoir contact andquality of reservoir, both Well-NMS2 and Well-NMS1 shouldbe expected to produce significantly better than Well-MSX.

Figure 9 compares the performance of the four wells used forthis study during their initial flow back period. The data showsthat Well-MSX and Well-NMS2 were the highest producers andflowed at almost the same rate of 65 MMSCFD, but Well-NMS2 achieved the same rate at higher FWHP, indicating abetter performer. On the other hand, Well-MSX produced at ahigher rate than Well-NMS1 at similar FWHPs.

The preliminary results clearly show that the stimulationtreatment in Well-MSX was very successful in enhancing theproductivity of the well; despite the fact that the well has only20% of the reservoir conductivity and 33% of the reservoircontact than Well-NMS2, it achieved a similar performance.

Moreover, Well-MSX outperformed Well-NMS1 despite thefact that it has only 13% of its reservoir conductivity and15% of its reservoir contact.

Further modeling using the nodal system analysis wasconducted to match recorded well performance andreservoir data, and then construct inflow performancerelationship (IPR) curves for forecasting purposes.Multilateral models were constructed and multiplesensitivity runs were made throughout this process. The typeof model used reduces the uncertainties associated withusing a traditional horizontal model, resulting in moreaccurate calculations. Figure 10 shows a graphicalrepresentation of the Well-NMS1 two-branch multilateralmodel used to calculate the IPR, Fig. 11. A one-branchlateral model was implemented to build the IPR for Well-MSX and Well-NMS2. Figure 12 summarizes all the IPRscalculated for these three horizontal wells.

As expected, the curves show much higher absolute openflow potential in Well-NMS1 and Well-NMS2, because of theirsignificantly longer horizontal sections than Well-MSX. Despitethe much higher flow potential exhibited by both Well-NMS2and Well-NMS1, Well-MSX productivity index (PI) is com -parable or better than the index of the other two producers.Figure 13 shows the estimated PI for each of the three wells usedin this study for FWHPs ranging from 1,000 psi to 3,000 psi.


Fig. 9. Initial gas rate performance comparison.

Fig. 10. Multilateral model built to simulate reservoir IPR for Well-NMS1 gascondensate producer well.

Fig. 11. Calculated IPR from multilateral reservoir model for Well-NMS1 gascondensate producer well.

Table 1. Kh comparison for high producer horizontal wells

Well Interval, ft Reservoir Conductivity(Kh, md-ft)

WELL-MSX 12,550-16,385 1,370(3,835 of total horizontal section)

WELL-MSX 12,550-13,991 780(1,440 of zone open to flow only)

WELL-NMS1(U) 11,523-16,135 3,466(4,610 of upper lateral)

WELL-NMS1 (L) 12,480-16,990 2,474(4,510 of lower lateral)

WELL-NMS2 11,930-16,364 4,310(4,434 of total horizontal section)


• Case 2: Actual Well-MSX performance after setting amultistage completion and implementing only three acidfracture stages.

• Case 3: Predicted Well-MSX performance if themultistage completion had been set to cover the entiredrilled horizontal section and six acid fracture stageshad been implemented as originally planned.

Figure 14 compares the IPR curves built for each of theabove listed cases. A single-branch multilateral model wasbuilt to evaluate Case 1, whereas a fracture model wasbuilt to evaluate Case 3. The analysis results showed thatWell-MSX would have reached the highest absolute openflow potential if the entire drilled horizontal length hadbeen stimulated and the lowest potential if the well had notbeen stimulated.

Data from the vertical lift performance curves derived fromthe IPR curves, Fig. 14, were used to perform material balancecalculations, using the MBAL software, to forecast cumulativegas production for each of the three evaluated cases. Allsensitivity runs were made assuming that the well would beflowed at the maximum rate, with an average FWHP of 1,200psig until unable to produce at natural flow conditions, due toreservoir pressure depletion.

The sensitivity runs showed that the stimulation treatmentincreased the well productivity twofold and will result in aforecasted net gas and condensate recovery increment of 10billion standard cubic feet (BSCF) and 230 million standardbarrels (MMsbbl), respectively, over the recovery from a non-stimulated condition. Moreover, the data also showed thatincreasing the number of stimulation stages would have resultedin a rate increase, but only marginal net recovery increment.

The quantification of the financial benefits derived from theimplementation of the stimulation treatment in Well-MSX wasobtained by performing an incremental economic analysiscomparing the cumulative production profiles of Case 1 (totalhorizontal length open to flow without stimulation) and Case2 (current condition: only 1,440 ft of horizontal length opento flow after stimulation). For the purposes of the analysis,Case 1 was considered the base case and Case 2 theincremental case.

The analysis was conducted using an in-house tool, whichincorporates production profiles over a maximum 15 year life,the capital cost of the cases evaluated, operating expenses, andcorporate pricing guidelines. The cost increment of themultistage completion and stimulation treatment in Well-MSXis reflected in the following results:

• The stimulation treatment will increase the net presentvalue (NPV) of the well by approximately $13 MM bythe end of its productive life, which is about 1.5 timeshigher than the NPV of the non-stimulated well.

• The total cost of the stimulated well will be paid out inless than 5 months, while the cost of the non-stimulatedwell will be paid out in 11 months.

ANALYSIS OF STIMULATION BENEFITS

A final study was conducted to quantify the productivityenhancement and financial benefits obtained from theimplementation of the multistage technology in Well-MSX.The quantification of the productivity enhancement benefitswas accomplished by assessing and comparing the followingthree cases by combining nodal system analysis and materialbalance equations:

• Case 1: Predicted Well-MSX performance with the entiredrilled horizontal section open to flow but not stimulated.

Fig. 12. Calculated IPR from multilateral reservoir model for Well-MSX, Well-NMS1 and Well-NMS2.

Fig. 13. Calculated productivity indexes for Well-MSX, Well-NMS1 and Well-NMS2.

Fig. 14. Calculated IPRs for three cases on Well-MSX well productivity evaluation.

• The return on investment of the stimulated well is 1.2times higher than the return of the non-stimulated well.

• The investment cost per MMSCFD produced from thestimulated well is lower than the cost for the non-stimulated well.

• Overall, the stimulated well is significantly moreprofitable than the non-stimulated well, which clearlyshows and confirms the benefits obtained from thetreatment.

CONCLUSIONS

Actual post-stimulation performance data from Well-MSXclearly showed that the treatment was highly successful bysignificantly increasing the productivity of the well, in spite ofthe fact that not all job objectives were achieved, due tomechanical problems encountered while setting the multistagecompletion.

All the analyses and comparisons described in this articleclearly indicated that the initial performance of Well-MSXwas similar or better than the initial performance observed inother horizontal gas producers, with significantly betterreservoir quality and conductivity, and longer horizontallength, than Well-MSX. With only 20% of the Kh and 33%of the horizontal length of Well-NMS2, one of the bestcurrent horizontal producers, Well-MSX achieved the sameinitial rate. Moreover, Well-MSX achieved a higher rate thandual-lateral horizontal producer Well-NMS1, which hasalmost eight times higher conductivity and seven times morehorizontal length.

The results from the different analyses also showed that thepost-stimulation results from Well-MSX would have beeneven better if the entire drilled horizontal section could havebeen stimulated and open to flow as planned. Consideringthat all analyses were conducted assuming maximum flowconditions throughout the life of the well, and that the wellwill be produced at a lower sustainable gas rate for properreservoir management, the data suggests that the well in itspresent condition will be an excellent performer.

Completing the well with the multistage assembly andperforming multiple acid fracture treatments will result in anincremental cumulative gas recovery of 10 BSCF and 230MMsbbls of condensate over a non-stimulated condition. Itwill also result in a $13 MM higher net present value over thelife of the well, and a much faster payout.

The overall success of the implementation of this newtechnology strongly supports additional field trials to ascertainits viability.

The post-stimulation performance of Well-MSX alsosupports considering working over the current number ofseverely damaged, underperforming horizontal producers tostimulate them effectively so that they can achieve theirmaximum potential.

ACKNOWLEDGMENTS

The authors wish to thank Saudi Aramco management fortheir support and permission to present the informationcontained in this article, with special thanks to MohammedAl-Sowayigh, M.A. Al-Khawajah, M.A. Al-Muhareb, HassanAl-Jubran, Francisco Garzon and Jairo Leal. Without theirvaluable input and support, these developments would nothave been possible.

REFERENCES

1. Seale, R., Athans, J. and Themig, D.: “An EffectiveHorizontal Well Completion and Stimulation System,” SPEpaper 101230, presented at the International PetroleumExhibition and Conference, Abu Dhabi, U.A.E., November5-8, 2006.

2. Lohoefer, D., Athans, J. and Seale, R.: “New Barnett ShaleHorizontal Completion Lowers Cost and ImprovesEfficiency,” SPE paper 103046, presented at the AnnualTechnical Conference and Exhibition, San Antonio, Texas,September 24-27, 2006.

3. Seale, R., Donaldson, J. and Athans, J.: “MultistageFracturing System: Improving Efficiency and Production,”SPE paper 104557, presented at the Eastern RegionalMeeting, Canton, Ohio, October 11-13, 2006.

4. Themig, D. and Athans, J.: “Effective Stimulation ofHorizontal Wells - A New Completion Method,” SPEpaper 106357, presented at the Technical Symposium ofSaudi Arabia Section, Dhahran, Saudi Arabia, May 21-23,2006.

5. Seale, R. and Athans, J.: “Using Open Hole HorizontalCompletion Technology to More Efficiently CompleteVertical Wells,” SPE paper 107930, presented at the RockyMountain Oil & Gas Technology Symposium, Denver,Colorado, April 16-18, 2007.

6. Seale, R.: “An Efficient Horizontal Open Hole MultistageFracturing and Completion System,” SPE paper 108712,presented at the International Oil Conference andExhibition, Veracruz, Mexico, June 27-30, 2007.



Hamad M. Al-Marri is aSuperintendent in the Southern AreaProduction Services Department(SAPED) in ‘Udhailiyah. He started hiscareer in 1991 with Southern AreaProducing and later joined the CollegeDegree Program to pursue his B.S.

degree in Chemical Engineering from Tulsa University,Tulsa, OK, graduating in 1999. Upon returning to SaudiAramco, Hamad worked as a Plant Engineer. In 2002, hereceived his M.S. degree in Petroleum Engineering, alsofrom Tulsa University.

Since that time, Hamad has been through variousassignments with oil and gas production engineering,drilling and workover, and reservoir engineering. He was ateam member in many key projects, including theHDGOSP-3 field development and affiliated intelligent field(I-Field) infrastructure construction. Prior to his currentposition, he was a Gas Production Supervisor charted tosupport the landmark development of the HWYH GasPlant 800 Increment.

Hamad has published and co-authored several SPE andGIS papers.

Carlos A. Franco is a PetroleumEngineer working for the GasProduction Engineering Department(GPED) in ‘Udhailiyah. He joined SaudiAramco in 2006 as a PetroleumEngineer working in production,stimulation, coiled tubing operations

and mineral scale strategy. Carlos’ experience includesworking for 10 years as a Production and Reservoir Engineerfor BP in Colombia operations, 3 years for Petróleos delNorte in Colombia as a Reservoir Engineer, 3 years for BakerChemical as a Stimulation Engineer and 3 years for PetrocolColombia as a Reservoir and Production Engineer.

He received his B.S. degree in Petroleum Engineering fromthe Universidad Nacional de Colombia, Medellin, Colombia.

Carlos has been an author or co-author of over 12papers on formation damage and aspects of oil field organicand mineral scales.

BIOGRAPHIES

Hassan M. Al-Hussain is a PetroleumEngineer working in the GasProduction Engineering Department(GPED) in ‘Udhailiyah.

Prior to joining Saudi Aramco in2006, Hassan received his B.S. degreein Petroleum Engineering from King

Fahd University of Petroleum and Minerals (KFUPM),Dhahran, Saudi Arabia.

J. Ricardo Solares is a PetroleumEngineering Consultant and aSupervisor with the Southern AreaProduction Engineering Department(SAPED) in ‘Udhailiyah. He has 25years of diversified oil industryexperience. Throughout his career,

Ricardo has held Reservoir and Production Engineeringpositions with Arco Oil and Gas and BP Exploration, whileworking in a variety of major carbonate and sandstonereservoirs located throughout the world’s majorhydrocarbon provinces in the Middle East, the Gulf ofMexico, Alaska and South America.

Since joining Saudi Aramco in 1999, he has beeninvolved with a variety of technical projects and planningactivities as part of large gas development projects.Ricardo manages a team responsible for the introductionand implementation of new technology, issuing operatingstandards, stimulation and production optimizationactivities, and completion design.

His areas of expertise include hydraulic fracturing andwell stimulation, all aspects of production optimization,completions and artificial lift design, pressure transient andinflow performance analysis, completions design, andeconomic evaluation.

In 1982 Ricardo received his B.S. degree in GeologicalEngineering and in 1983 he received his M.S. degree inPetroleum Engineering, both from the University of Texasat Austin, Austin, TX. He also received an MBA in Financefrom Alaska Pacific University, Anchorage, AK in 1990. Hereceived the 2006 Society of Petroleum Engineers (SPE)Regional Award in the area of Management andInformation, and a SPE Technical Editor award for hiswork on the Editorial Review Committee. Ricardo has alsopublished over 20 SPE papers and articles in a variety ofinternational technical publications.

ABSTRACT

Recent evolution in oil field technologies has instigated a greatrevolution in the oil and gas industry all over the world,leading to the emerging development of intelligent fields (I-Fields)1-4. The integration of I-Field technologies, whetherdownhole or at surface coupled with communicationnetworks, along with sophisticated simulation and monitoringapplications, has led to significant advancements not only inmonitoring and control capabilities, but also in decisionmaking processes5. Therefore, the overall system upgrade hasresulted in an enhancement of the field surveillance, whichwill lead to higher levels of oil production.

A comprehensive redevelopment and I-Field trans formationof three elderly remote onshore oil fields in Saudi Arabia hastaken place where extensive drilling and workover programshave been reinitiated to complete both oil production andperipheral water injection wells, equipping them with the latestdownhole production technologies. The project has alsoinvolved construction of new oil and gas processing and waterinjection facilities, which are being linked with the wells via astate-of-the-art fiber optic communication network forcontrolling both subsurface and surface parameters and datasurveillance in real-time. Further integration of I-Fieldcomponents, such as Permanent Downhole Monitoring Systems(PDHMS), Smart Well Systems, Multiphase Flow Meters(MPFM), Single Phase Flow Meters, pressure and temperaturesensors with specially tailored monitoring, and simulationsoftware, has facilitated the development and implementationof optimized production and injection strategies.

This article will discuss the development strategy for thethree fields, sharing the lessons learned from this project.Moreover, examples, such as well performance monitoringand validation, crude blend assessment and assurance andreservoir pressure mapping, which are all being performed inreal-time, will be presented. In addition, this article willillustrate how the integration of I-Field components haseffectively helped in optimizing the production from aportfolio of developed reservoirs.

INTRODUCTION

The Abu Hadriya, Fadhili and Khursaniyah (AFK) complexconsists of three fields that share common surface

infrastructure in fluid processing facilities and pipelinenetworks. Historically, the production from the AFK fieldsstarted in the early 1960s, but the fields were shut-inbetween 1983 and 1990 due to the low demand for oil in theinternational markets. Production resumed from only twofields for about three years during the Gulf crisis in the early1990s. Production from all of the producing reservoirs wassupported then by gravity injection, since existing facilitiesdid not have power water injection capability. All producedassociated gas was flared at that time too, since there wereno gas handling facilities. Furthermore, the originaldevelopment strategy for the three fields was based onindividual field production schemes, where each field had itsown oil processing facility and produced a distinctive crudegrade, Fig. 1.

Saudi Aramco has recently embarked on the developmentof several fields, including the AFK fields, with an aim totransform the elderly and remote fields into state-of-the-artintelligent fields (I-Fields) equipped with proper handlingfacilities for oil, water and gas6-9. The new AFK projectmainly consists of a twofold plan. The first part calls for thedrilling of new wells, both oil producers and water injectors.The newly drilled water injection wells are part of a plannedperipheral water injection program to ensure adequatepressure maintenance in AFK reservoirs. The second part callsfor the implementation of I-Field components in the fields’


Revitalization of Old Asset Oil Fields into I-Fields

Authors: Dr. Mohammed N. Al-Khamis, Konstantinos I. Zormpalas, Hassan M. Al-Matouq and Saleh M. Al-Mahamed

Fig. 1. AFK fields showing old and new processing facilities.


DATA MANAGEMENT

Real-time data captured from the AFK fields is delivered todesktop applications by a series of different components thatconstitute the infrastructure of data management10, Fig. 2.Data transmitted by instrumentation systems in any well sitestarts its path from the Remote Terminal Unit (RTU). TheRTU communicates data collected from site systems toSCADA servers that represent the central processing andcontrol system in the field. Plant Information (PI) servers thenhandle the archival of data; they form the data source forenterprise database and applications.

Field Data Network

The RTU of each well site exchanges data telegrams with theSCADA system over a fiber optic based data communicationnetwork called Open Transport Network (OTN). This networkconsists of three OTN rings for the three fields and supports atotal of 90 well sites. Each ring is configured to be in loopbackmode for self-healing if any OTN node fails to communicatebecause of power outage or any other reason. Before reachingthe SCADA system, the three OTN rings of the AFK fields meettogether in a redundant OTN switch located in the ControlCenter Room (CCR) of the processing facility.

SCADA System

The local network of the SCADA system is based on threeredundant servers, the Front End Processor (FEP) server,SCADA server and database server. The FEP server acts asthe interface between the RTUs and the SCADA server.There are two redundant FEP servers and each one cansupport 60 RTUs. Data coming from the OTN network isscanned by the FEP server and passed to the SCADA server,where all data processing and calculations are handled. TheSCADA server holds the online database “process image”that contains the current status of field data and controlcommands sent to the RTUs.

In addition to holding the setup information of SCADAdisplays and configurations, the database server is used for

infrastructure, which will enhance the automation andcommunication network of downhole equipment with surfacefacilities. In addition to the twofold development plan, a newprocessing facility to handle 500,000 barrels oil per day(MBOD) of Arabian Light crude blend, a new gas plant toprocess 1 billion cubic feet per day (BCFD) of sour gas fromthis increment, as well as from other nearby fields, a waterinjection plant with a capacity of 1.1 billion barrels of waterper day (BBWD) to support reservoir pressures and acomplete infrastructure of flow line networks to interconnectthe three fields with the centralized processing facility havebeen built. Moreover, the new facility setup has the capabilityof comingling different crude streams from the three fields toyield different crude grades.

The newly drilled wells of the redevelopment project havebeen completed with up-to-date downhole and surfaceproduction technologies to monitor and optimize theirproducing performance. These include Remotely OperatedChokes and Diversion Valves, Emergency Shut-down Systems(ESDs), Permanent Downhole Monitoring Systems (PDHMS),Compact Multiphase Flow Meters, Electric SubmersiblePumps (ESPs) and Smart Well Completions (SWCs). All thesetechnologies have been connected at surface with a fiber opticnetwork and a state-of-the-art Supervisory Control and DataAcquisition (SCADA) system to provide real time dataacquisition and monitoring of these technologies for instantdecision making. Table 1 shows the number of the individualcomponents of modern technologies used in theredevelopment phase of the AFK fields.

The challenges of the AFK fields, and therefore thedecision to implement the I-Field concept, are the remotenessof these fields from existing infrastructure, and thecomplexity of the crude blend where 11 reservoirs withdifferent crude grades will be produced to yield a distinctiverequired crude grade. These challenges necessitate atransformed development to facilitate reservoirs and facilitiesmonitoring in real time. In the following sections, severalexamples will be discussed to demonstrate how theintegration of these innovative technologies has enabledSaudi Aramco to revitalize the old AFK assets intomodernized I-Fields.

Table 1. Modern production technologies installed in AFK fields

Modern Technologies No.Pressure and Temperature Transmitters 751Remotely Operated Chokes 154Remotely Operated Diversion Valves 227Permanent Downhole Monitoring System (PDHMS) 48Emergency Shut-down Systems (ESD) 70Multiphase Flow Meters (MPFM) 25Orifice Flow Meter 93Electrical Submersible Pumps (ESP) 17Smart Well Completions (SWC) 4

Fig. 2. Data management infrastructure.

long-term data storage. It archives data received from theprocess image using an external Storage Area Network (SAN).It receives data in a predefined “Basic Cycle” and computesthe values of higher cycles (i.e., hours, days, years, or anydefinable period) either by averaging or totalizing. Each cyclespecifies a limited lifetime for keeping the archived data. Thislifetime and other cycle parameters are defined in what iscalled an “archive plan” and any reading can be associatedwith a predefined archive plan. This long-term archiving is thebasis for SCADA historical data reports and trend graphs.

Data Historian and Applications

Real-time data acquired by the SCADA system is forwardedby a PI interface node, which resides on the SCADA network,to the area PI system on the corporate network, Fig. 2. Thisarea PI cluster is a high processing server that archives datareceived from the AFK fields, as well as other fields in thesame area. The PI system delivers real-time data to theengineer’s desktop through user-friendly Windows basedgraphical displays while providing more efficient long-termdata archiving and powerful data processing andmanagement. Area PI systems are also interfaced with thecorporate database, where many enterprise petroleumengineering applications are then utilized to process andmanipulate real-time data stored in this database.

FIELD MANAGEMENT

Given the rate at which the I-Field concept has been nurturedduring the last decade, countless benefits and improvements inoil and gas production operations can now be realized. Asmentioned earlier, the general scope of the AFK field projectwas to bring these three assets, which were at a standstill, to amodernized facility that will enhance and optimize the overalloperation of these fields. The following section highlightssome of the major features of this project.

Control Capabilities

The proper integration of I-Field components, such asMPFMs, has enabled accurate measurements of wellproduction rates from the 11 developed reservoirs of the threeAFK fields, which in turn has ensured correct blending of thevarious crude grades. At the same time, this integration hasenabled proper production allocation for every well, which isvery crucial for reservoir simulation. Furthermore, the use ofRemotely Operated Chokes (ROCs) and SWCs to adjust wellrates, as well as to switch them to test headers, has facilitatedprompt control of individual wells without the need of fieldoperator support, Fig. 3. Since wells are spread over ageographical distance of more than 50 km by 30 km, withoutthis facilitation it would have been extremely difficult to


Fig. 3. Flow of AFK field wells is remotely controlled.


at the same time tangible cost savings have been realized fromthe utilization of information from I-Field components andmethodologies. Furthermore, this successful approach hasminimized our dependency on costly wireline surveys, andimproved the safety of our field operations by considerablydecreasing human interaction.

Optimizing Well Performance

Incorporating I-Field technologies in the AFK fields hasfacilitated optimization of the performance of both oilproduction and water injection wells. For example,networking real time reservoir data and remote controlinstruments from the field, coupled with monitoring andsurveillance systems, has enabled fine-tuning of both theproduction and injection rates in a remarkably short time.This has accelerated the decision making process to meetthese targets, and at the same time has assured that the setproduction and injection strategies are fulfilled at all times,Fig. 5. In addition, the system can display the life statisticsof the total number of active wells, shut-in wells,overproducing or injecting wells, and underproducing orinjecting wells.

Moreover, the performance of all the wells is furtheroptimized by an automated multi-rate test validationtechnique using commercial flow simulation software. Thisprocedure involves modeling the results of rate testsperformed in the field to track changes in reservoir pressures,and well productivity or injectivity with time without the needfor conducting costly Pressure Transient tests, Fig. 6. Byestablishing this process, engineers were able to closelymonitor reservoir pressure changes around the wells, andaccordingly adjust the distribution of the water injectionvolumes in the various developed reservoirs to achieve the bestreservoir sweep.

adjust the crude blend and implement optimized productionand injection strategies.

Furthermore, the system has another unique controlfeature where individual well sites, and even each individualfield can be remotely shutdown via the activation of bothsurface and subsurface safety valve systems in case of anemergency. The latter feature was deemed necessary due tothe close proximity of the sour crude producing AFK fields toa national public highway and other nearby support andindustrial facilities.

Real-Time Reservoir Surveillance

Real-time reservoir pressure management was also animportant task considered during the planning andimplementation phases of the AFK field’s development. Sinceall three fields are under pressure maintenance usingperipheral water injection patterns, close monitoring ofreservoir pressure is very crucial to ensure that theimplemented production and injection strategies areappropriate at all times and to make timely adjustments inthese strategies as deemed necessary.

In general, there are two sources for reading reservoirpressures: real time data from the installed 31 PDHMS and17 ESP systems, and estimated reservoir pressure data fromflow simulation models. Integration of these two reservoirdata sources with the field management data mappingpackage has enabled us to generate real-time reservoirpressure maps. Figure 4 shows snapshots of isobaric mapsrepresenting times before and after the production andinjection startups. These maps can therefore be constantlyevaluated for reservoir pressure propagation and used tomake necessary production and injection rate adjustments toensure proper reservoir sweeps.

As a result of this approach, reservoir surveillance hasimproved significantly. The decision making process has beenadvanced from the normal six month period to real-time, and

Fig. 4. Real time reservoir pressure mapping.

Fig. 5. Reservoir view showing real time well status.

Operation Enhancement

As highlighted earlier, one of the challenges in this projectis the complexity of the crude blend where 11 reservoirswith different crude grades ranging from 24.1° API to 38.6°API will be produced, and a meticulous blending processmust take place to yield a distinctive grade of ArabianLight crude. Therefore, it is imperative to establish amechanism that will ensure that the crude properties fromthe AFK fields meet the required specifications at all times.Consequently, real time monitoring and control areessential elements when it comes to production allocationand in turn to appropriate crude blending. For instance, bycontrolling in real time the physical flow of oil from asystem of wells or even an entire reservoir, one can allowlighter or heavier fractions to be produced, which in turnwill govern the outcome of the API crude density of thefinal blend.

For this objective, the monitoring surveillance systems arealso utilized to continuously assure the crude grade quality.The system provides active hot-links for each field or reservoirand a tree map representation showing the total production,injection and supply rates as compared to the recommendedtargets, as well as some Key Performance Indicators (KPIs)and Key Operating Parameters (KOPs) enabling engineers toconstantly monitor the performance of the wells and thequality of the blended crude by estimating the blendedproduced crude grade, Fig. 7.

Aside from monitoring the wells and field’s performance,the systems can also monitor the performance of rotatingequipment, such as ESPs, corrosion inhibitor units, CathodicProtection and field data communication and generatecustomizable reports of all gathered data. Figure 8 shows anexample of an extracted report, while Fig. 9 shows anexample of a well completed with ESP where the pump limitsare being configured and monitored by the system to flag anyabnormality in the proper pump operation. In this later case,the pump diagnosis can be performed in real time, enablingengineers to adjust the pump settings when necessary. This inturn has enabled the proper operation of the ESPs within theequipment operational envelope for optimum performance,which will also eventually prolong the life of the equipment.

CONCLUSIONS

The project of revitalizing the AFK complex of fieldsutilizing I-Field technologies was driven by the need tomodernize and optimize a facility that was below itspotential. Saudi Aramco management realized theopportunity to enable previously identified reserves to come


Fig. 6. Multi-rate test validation using flow simulation models.

500

1000

1500

2000

2500

3000

0 5,000 10,000 15,000 20,000 25,000 30,000Inje

ctio

n W

ellh

ead

Pre

ssu

re (

psi

g)

Injection Rate (BWPD)

Multi-RateWell Model

Fig. 7. Views from the monitoring surveillance system showing some key performance parameters.


Fig. 8. Sample of the generated customizable reports.

Fig. 9. Real time ESP parameters monitoring and control.


onstream quickly in an operation with remote control andsurveillance that allowed fast decision making toward theoptimization of the entire process, from the wellhead to thepipeline transportation system. The factors that mandatedthe revitalization of AFK assets into I-Fields can besummarized as follows:

• Construction of a central and modern facility, designedto handle the produced fluids from all three fields, andbecome a substitute for the old individual facilities ineach field.

• Capability of water injection in all three fields tosupport reservoir pressure.

• Capacity to process produced sour gas and avoidflaring.

• The need to produce a certain crude blend from amixture of 11 crude grades from different reservoirsamong the three fields, and to implement I-Fieldmethodologies to assure crude quality compliance.

• Ability to remotely control key parameters and monitorvital equipment in real-time to optimize the flow ofhydrocarbons from the fields to the processing facility,which are spread over a geographical distance of morethan 50 km by 30 km.

• Minimization of human interaction associated with fieldoperations in a source crude producing environment.

ACKNOWLEDGMENTS

The authors wish to thank the Northern Area ProductionEngineering and Well Services management of Saudi Aramcofor their support and permission to present the informationcontained in this article. Acknowledgment is also extendedto the AFK Fields Development Team for their support inthis study.

This article was presented as SPE paper 126067 at theSPE Saudi Arabia Section Technical Symposium, al-Khobar,Saudi Arabia, May 9-11, 2009.

REFERENCES

1. Sengul, M. and Bekkousha, M.A.: “Applied ProductionOptimization: I-Field,” SPE paper 77608, presented at theSPE Annual Technical Conference and Exhibition, SanAntonio, Texas, September 29 - October 2, 2002.

2. Ouimette, J. and Oran, K.: “Implementing Chevron’s I-Fieldat the San Ardo, California, Asset,” SPE paper 99548,presented at the SPE Intelligent Energy Conference andExhibition, Amsterdam, The Netherlands, April 11-13, 2006.

3. Cramer, R.: “Back to the Future - A Retrospective on 40Years of Digital Oil Field Experience,” SPE paper111478, presented at the SPE Intelligent EnergyConference and Exhibition, Amsterdam, The Netherlands,February 25-27, 2008.

4. Adeyemi, O.S., Shryock, S.G., Sankaran, S., Hostad, O.and Gontijo, J.: “Implementing I-Field Initiatives in aDeepwater Green Field, Offshore Nigeria,” SPE paper115367, presented at the SPE Annual Technical Conferenceand Exhibition, Denver, Colorado, September 21-24, 2008.

5. Burda, B., Crompton, J., Sardoff, H. and Falconer, J.:“Information Architecture Strategy for the Digital OilField,” SPE paper 106687, presented at the SPE DigitalEnergy Conference and Exhibition, Houston, Texas,April 11-12, 2007.

6. Al-Kaabi, A.O., Al-Afaleg, N.I., Pham, T., et al.: “Haradh-III: Industry’s Largest Field Development using MaximumReservoir Contact Wells, Smart Well Completions and I-Field Concept,” SPE paper 105187, presented at the 15th

SPE Middle East Oil & Gas Show and Conference,Bahrain, March 11-14, 2007.

7. Al-Arnaout, I.H., Al-Driweesh, S.M. and Al-Zahrani,R.M.: “Production Engineering Experience with theFirst I-Field Implementation in Saudi Aramco atHaradh-III: Transforming Vision to Reality,” SPE paper112216, presented at the SPE Intelligent EnergyConference and Exhibition, Amsterdam, TheNetherlands, February 25-27, 2008.

8. Al-Malki, S., Al-Buraikan, M.M., Abdulmohsin, R.A.,Aheyd, R. and Al-Hamzani, H.: “I-Field CapabilitiesEnable Optimizing Water Injection Strategies in SaudiArabian Newly Developed Oil Fields,” SPE paper 120835,presented at the SPE Saudi Arabia Section TechnicalSymposium, Al-Khobar, Saudi Arabia, May 10-12, 2008.

9. Al-Dossary, F.M., Al-Ghamdi, A.A. and Al-Ahmari, A.S.:“Experiences and Benefits Gained through Implementationof the First Intelligent Field in Saudi Aramco (Qatif Field),”SPE paper 118008, presented at the Abu DhabiInternational Petroleum Exhibition and Conference, AbuDhabi, U.A.E., November 3-6, 2008.

10. Al-Dhubaib, T.A., Almadi, S.M., Shenqiti, M.S. andMansour, A.M.: “I-Fields Data Acquisition and DeliveryInfrastructure: Case Study,” SPE paper 112201, presentedat the SPE Intelligent Energy Conference and Exhibition,Amsterdam, The Netherlands, February 25-27, 2008.


Hassan M. Al-Matouq is a ComputerEngineer with the Northern AreaTechnical Support Department. He has5 years of experience in computerapplications development andpetroleum engineering systems. Hassanparticipated on the commissioning and

startup team of the Abu Hadriya, Fadhili and Khursaniyah(AFK) fields’ development project.

Hassan received his B.S. degree in Computer Engineeringfrom King Fahd University of Petroleum and Minerals(KFUPM), Dhahran, Saudi Arabia in 2004.

Saleh M. Al-Mahamed is a PetroleumEngineer working for the NorthernArea Production Engineering and WellServices Department (NAPE&WSD) inthe Abu Hadriya, Fadhili andKhursaniyah (AFK) fields.

He received his B.S. degree inPetroleum Engineering in 2007 from the University ofLouisiana at Lafayette, Lafayette, LA. Saleh joined SaudiAramco in 2002.

BIOGRAPHIES

Dr. Mohammed N. Al-Khamis is aProduction Engineering Supervisorwith the Ras Tanura ProductionEngineering Division. He has 9 yearsof academic experience and more than17 years of work experience in variousdepartments within Saudi Aramco, and

has published and presented numerous technical papers andresearch reports.

In 1988, Mohammed received his B.S. degree and in1995 he received his M.S. degree, both in PetroleumEngineering from King Fahd University of Petroleum andMinerals (KFUPM), Dhahran, Saudi Arabia and in 2003,he received his Ph.D. degree in Petroleum Engineering fromthe Colorado School of Mines, Golden, CO.

Konstantinos I. Zormpalas joinedSaudi Aramco in 2006 and has beeninvolved with the Safaniya field whileworking in the Northern AreaProduction Engineering & WellServices Department (NAPE&WSD).Prior to joining Saudi Aramco, he was

the Production Engineer of a field in the Sahara desert inAlgeria, and worked throughout the project from thecommissioning phase of the Central Processing Facility foroil and gas, to start-up for first oil and to the full fielddevelopment.

Konstantinos has 16 years of production engineeringexperience in production optimization, well completions,artificial lift, well testing and workovers. He has hadnumerous international postings in the United States,Argentina, Germany, Russia, Algeria and Qatar.

Konstantinos graduated in 1992 from Mississippi StateUniversity, Mississippi State, MS with both his B.S. andM.S. degrees in Petroleum Engineering.


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These guidelines are designed to simplify and help standardizesubmissions. They need not be followed rigorously. If youhave additional questions, please feel free to contact us atPublic Relations. Our address, fax and phone numbers arelisted on page 71.

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Spring 2010 December 2, 2009 March 31, 2010Summer 2010 March 3, 2010 June 30, 2010Fall 2010 June 1, 2010 September 30, 2010Winter 2010 September 1, 2010 December 31, 2010

Additional Content Available Online at: www.saudiaramco.com/jot


USE OF ADVANCED NONCONVENTIONAL TECHNOLOGY TO IMPROVE FLOW PROPERTIES,UPGRADING/DESULFURIZING HEAVY AND HIGH SULFUR CRUDEDr. M. Rashid Khan, Emad Naji Al-Shafei and Dr. Nicholas E. Leadbeater

ABSTRACT

The nonconventional technology of microwave irradiation was studied to desulfurize heavy crude oil and to treat tightemulsion. The desulfurization treatment aimed to reduce the sulfur content, thereby improving the price differential of heavycrude oil sales. The treatability of tight emulsion is aimed to increase the crude oil separation from water in less time, withno chemical additions.

EVALUATION OF NEW STIMULATION TECHNIQUE TO IMPROVE WELL PRODUCTIVITY IN A LONG, OPENHOLE HORIZONTAL SECTION: CASE STUDYJ. Ricardo Solares, Carlos A. Franco, Hamad M. Al-Marri, Francisco O. Garzon, Khalid S. Asiri, H.A. Saeed, Wael M. Omairi

and Guillermo A. Izquierdo

ABSTRACT

Saudi Aramco has significantly increased the number of horizontal gas producers over the past five years in an attempt tomaximize well productivity through maximum reservoir contact (MRC), while reducing the need for hydraulic fracturingstimulation, commonly required in most vertical producers. Although the majority of horizontal producers have metexpectations, a few of these did not, due to formation damage during drilling operations. The highly heterogeneous nature ofthe reservoir resulted in low porosity and permeability in different areas of the field, destabilization and precipitation ofmineral and organic scales in the tubulars and formation, and condensate banking effects.

MINIMIZING WELLBORE DAMAGE IN A SANDSTONE RESERVOIR USING EFFECTIVE MUD MANAGEMENTPRACTICESDr. Ali S. Rabba, James E. Phillips, Saleh M. Al-Ammari and Monir Mohamed

ABSTRACT

Causing formation damage in sandstone reservoirs through poor drilling fluids management is a crucial factor that can affectwell productivity. An integrated team assigned to manage the drilling of horizontal producers for field development,developed a mud management plan to monitor drilling fluid properties and maintain mud system specifications to minimizeformation damage in the field’s sensitive sandstone reservoir. This article discusses the implementation of the engineered oil-based drill-in fluid (DIF), particle size monitoring, and drilling and completion methods designed to minimize reservoirformation damage and help maximize well productivity.

WELL TEST ANALYSIS IN NATURALLY FRACTURED GAS CONDENSATE RESERVOIRS BELOW DEW POINTPRESSUREAhmed M. Al-Baqawi and Bandar H. Al-Malki

ABSTRACT

Gas condensate reservoirs below dew point pressure have been an area of interest for many studies in the petroleum industryseeking to properly answer questions surrounding the impact on well performance when the reservoir pressure falls belowdew point pressure. Many of the studies have concentrated on the effects of liquid condensate drop-out in homogeneousreservoirs. This article focuses on the gas condensate drop-out impact in naturally fractured (dual porosity) carbonatereservoirs and the effects on well test analysis interpretations due to the changing oil/gas relative permeabilities in theappearing composite zones around the wellbore below dew point pressure.

REAL-TIME GEOLOGY/PETROPHYSICS IN COMPLEX CARBONATE RESERVOIRSRamsin Y. Eyvazzadeh, Rami H. BinNasser and David G. Kersey

ABSTRACT

Geosteering technology has played a key role in enhancing hydrocarbon production and recovery in many reservoirs throughoutthe world. Traditionally, Logging While Drilling (LWD) measurements are used to determine petrophysical parameters, such asporosity and hydrocarbon saturation to geosteer wells in the reservoir. In many complex carbonate reservoirs, fluid flow charac-teristics are generally difficult to predict and the most porous intervals are not always the best reservoirs, as intervals ofequivalent porosity can exhibit large variations in permeability. Additionally, changes in depositional and digenetic environmentsprovide for a complex geology that poses challenges in well placement.

OPEN HOLE SIDETRACK: A TRANSFORMATION IN DRILLING DUAL LATERAL KHUFF RESERVOIR GAS WELLS INTHE KINGDOM OF SAUDI ARABIAKhalid Nawaz, Omar A. Al-Faraj, Naser A. Ajmi, Amir H. Awan, Jaywant Verma and Sukesh Ganda

ABSTRACT

This article describes the application of the open hole sidetrack (OHSDTR) technique to drill deep gas multilateral horizontalwells in Saudi Arabia. The drawbacks of earlier whipstock exits were studied and an alternate technique was proposed andimplemented.

ANALYSIS OF DEPOSITION MECHANISM OF MINERAL SCALES PRECIPITATING IN THE SAND FACE ANDPRODUCTION STRINGS OF GAS-CONDENSATE WELLSCarlos A. Franco, J. Ricardo Solares, Hamad M. Al-Marri, A.E. Mukhles, Nezar H. Ramadhan and Ali H. Al-Saihati

ABSTRACT

Thick deposits of various types of mineral scales at present are forming in the production systems of gas condensate wellsproducing from carbonate reservoirs. These mineral scales precipitate when ideal thermodynamic conditions and dissolvedminerals present in formation waters combine. Without remedial action over time, these deposits can grow thicker and end upplugging tubulars and the reservoir.

COLLABORATIVE DEVELOPMENT OF A SLIM LWD NMR TOOL: FROM CONCEPT TO FIELD TESTINGDr. Ridvan Akkurt, Dr. Alberto F. Marsala, Douglas Seifert, Ahmed A. Al-Harbi, Carlos A. Buenrostro, Dr. Thomas Kruspe,

Holger F. Thern, Dr. Gerhard Kurz, Martin Blanz and Asbjorn Kroken

ABSTRACT

Nuclear Magnetic Resonance (NMR) was identified as a critical technology for reducing uncertainty and minimizing risk duringthe planning phase of a major field development project. The reservoirs in the subject field contain heavy oil/tar in the flanks,and accurate knowledge of viscosity trends became essential for the placement of water injectors. Since NMR logs can be usedto estimate heavy oil viscosity, the development plan required running logging while drilling (LWD) NMR logs in the extended-reach horizontal injectors, in addition to some selected producers.

SUCCESSFUL APPLICATION OF INNOVATIVE FIBER-DIVERTING TECHNOLOGY ACHIEVED EFFECTIVE DIVERSIONIN ACID STIMULATION TREATMENTS IN SAUDI ARABIAN DEEP GAS PRODUCERSMoataz M. Al-Harbi, J. Ricardo Solares, Abdulaziz Al-Sagr, Ricardo Amorocho and Venkateshwaran Ramanathan

ABSTRACT

Acid fracturing has been an integral part of Saudi Aramco’s gas development strategy for the vertical wells in the Khuffcarbonates over the last several years. The Khuff formation is a deep gas carbonate reservoir that is ideally suited for acidfracturing. During acid fracturing, the wormholes created by the reaction results in excessive fluid loss. Controlling fluid loss iskey to optimizing acid fracturing treatments by creating longer and wider fractures. Diesel emulsified acid for deeper penetrationand in-situ gelled acid, a polymer-based system, are used to control excessive leakoff at different stages of the treatment alongwith the alternating stages of a polymer pad.

Documents

Jot Fall 2009