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Best Practice in Understanding andManaging Lost Circulation Challenges

Hong (Max) Wang, SPE, Ronald Sweatman, SPE, Bob Engelman, SPE, Halliburton; Wolfgang Deeg (formerlyHalliburton), SPE; Don Whitfill, SPE, Mohamed Soliman, SPE, Halliburton; and Brian F. Towler, SPE, University of Wyoming

SummaryLost circulation has been one of the major challenges that causemuch nonproductive rig time each year. With recent advances,curing lost circulation has migrated from “plugging a hole” to“borehole strengthening” that involves more rock mechanics andengineering. These advances have improved the industry’s under-standing of mechanisms that can eventually be translated into bet-ter solutions and higher success rates. This paper provides a reviewof the current status of the approaches and a further understandingon some controversial points.

There are two general approaches to lost circulation solutions:proactive and corrective, based on whether lost circulation hasoccurred or not at the time of the application. This paper providesa review of both approaches and discusses the pros and cons re-lated to different methods—from an understanding of rock me-chanics and operational challenges.

IntroductionLost circulation (LC) is defined as the loss of whole mud (e.g.,solids and liquids) into the formation (Messenger 1981). There aretwo distinguishable categories of losses derived from its leakoffflowpath: Natural and Artificial. Natural lost circulation occurswhen drilling operations penetrate formations with large pores,vugs, leaky faults, natural fractures, etc. Artificial lost circulationoccurs when pressure exerted at the wellbore exceeds the maxi-mum the wellbore can contain. In this case, hydraulic fractures aregenerally created.

During the last century, lost circulation presented great chal-lenges to the petroleum industry, causing significant expenditureof cash and time in fighting the problem. Trouble costs have con-tinued into this century for mud losses, wasted rig time, and inef-fective remediation materials and techniques. In worst cases, theselosses can also include costs for lost holes, sidetracks, bypassedreserves, abandoned wells, relief wells, and lost petroleum re-serves. The risk of drilling wells in areas known to contain theseproblematic formations is a key factor in decisions to approve orcancel exploration and development projects.

Background literature (Messenger 1981) on the subject de-scribes many methods and materials used to remedy lost circula-tion. Many of these methods worked in some wells but not inothers. Trial and error applications almost always resulted in acostly learning curve.

A field practices study (API 1991) of cementing wells, pub-lished by the American Petroleum Institute (API) in 1991, com-piled drilling and production surveys and trade journal data for 339fields worldwide between 1980 and 1989. The number of fields ineach area is presented for general information and may not repre-sent all wells or fields in that specific area. The North Americanfields include fields in Canada, Mexico, and the USA. Listedamong the many types of data sourced in this study is LC infor-mation in relevant fields. This LC data was analyzed for this paperto obtain the LC event frequencies of occurrence presented inTable 1. The LC data analysis indicates that up to 45% of all wells

in the 339 fields require intermediate casing or drilling liner stringsto isolate LC zones and prevent LC while drilling deeper to totaldepth (TD). Even after using these extra pipe strings, LC eventsstill occurred in 18 to 26% of all the hole sections drilled inrelevant fields. Some fields had higher occurrences of LC eventsranging from 40 to 80% of wells. In recent years, these percentageslikely increased as the number of shallow, easy-to-find reservoirssteadily declined and industry operators intensified their search fordeeper reservoirs and drilled through depleted or partially depletedformations. Conventional lost-circulation materials (LCM), in-cluding pills, squeezes, pretreatments, and drilling procedures of-ten reach their limit in effectiveness and become unsuccessful inthe deeper hole conditions where some formations are depleted,structurally weak, or naturally fractured and faulted.

To address these issues, new LC solutions and concepts, suchas borehole strengthening or wellbore pressure containment(WPC), evolved (Alberty and Mclean 2004; Aziz et al. 1994; Fuhet al. 1992). The mechanisms behind various means proposed andused to enhance WPC are still debated and are not fully under-stood. Proposed mechanisms include sealing incipient fractures atthe wellbore wall; propping open multiple short fractures at thewellbore wall, thus increasing compressive stresses around thewellbore; and sealing fractures with various materials using a hesi-tation-squeeze technique.

Based on the ongoing debate of these emerging new tech-nologies for controlling lost circulation, this paper intends toprovide a comprehensive review and analysis for a better under-standing of both proactive and corrective borehole strengthen-ing technologies.

Proactive Borehole StrengtheningSuccess and Issues. Muds have been pretreated with particulateshaving a broad size-distribution spectrum for years, yielding someclear benefits (Ali et al. 1991; Fuh et al. 1992; Aston et al. 2004).Based on systematic lab studies, this approach was originally as-sumed to work by “tip screenout,” isolating the fracture tip fromthe wellbore pressure, thus stopping fracture propagation (Fuhet al. 1992). The pressure containment improvement realized bythis approach depends strongly on the actual fracture length anddecreases rapidly with increasing fracture length (Deeg and Wang2004). To help improve the pressure containment using this ap-proach, the fracture should be bridged or sealed as quickly aspossible before it has a chance to extend a significant distance intothe formation.

Recent improvements in this technology, which include use ofparticulate-treated mud as weak zones are penetrated, have shownsignificant success in substantially increasing WPC (Alberty andMclean 2004; Aston et al. 2004). These successes are supported bystrong evidence from pre- and post-treatment pressure tests. Be-cause of their capability to strengthen during drilling, the use ofthese special muds offers an excellent approach for drilling de-pleted formations and has achieved substantial success in the field.

Its theory, often referred to as “stress caging,” states that theborehole is strengthened by creating microfractures, then pluggingand propping them open with particulates, increasing the hoopstress. The size distribution of the particulates to be added to themud is determined by using the basic hydraulic-fracturing theoryand an assumed fixed-fracture length of 6 inches (in.).

The theory that explains this mechanism is not totally accepted,because finite element fracture simulations show (Abousleimen

Copyright © 2008 Society of Petroleum Engineers

This paper (SPE 95895) was first presented at the 2005 SPE Annual Technical Conferenceand Exhibition, Dallas, 9–12 October, and revised for publication. Original manuscript re-ceived for review 6 October 2006. Revised manuscript received 11 September 2007. Paperpeer approved 10 November 2007.

168 June 2008 SPE Drilling & Completion

et al. 2005) that a stable microfracture that could be plugged byparticulates in the described manner (Alberty et al. 2004) isnot present. Further, it was found that two published borehole-strengthening data points are still within the Kirsch hoop-stress range for an impermeable circular wellbore-boundarycondition (Abousleimen et al. 2005). The Kirsch hoop-stress equa-tion defines the upper bound of fracture-initiation pressure for aperfectly circular wellbore in impermeable rock. It is thereforepossible that the special mud actually satisfied the boundary con-dition of impermeability, sealing pore throats, and keeping fluidfrom leaking off into the formation. The assumed 6-in. fracturelength also lacks support and could easily be exceeded duringfracture initiation.

Sealing Short Fractures. It is widely accepted that the formationbreakdown pressure can be much greater if the wellbore can betreated as an impermeable boundary in depleted formations (Gid-ley et al. 1989). Today’s drilling fluids used for drilling depletedformations frequently provide good fluid-loss control, but we havenot seen a particular conventional drill fluid that alone can prevent LC.

Although plugging rock-matrix pore throats can create a nec-essary condition, treating short fractures may also be important. Intectonically active areas, Sh can be much smaller than SH. Undercertain conditions, fractures can initiate regardless of wellborepressure. Joints created by tectonic activities may be open andready to take fluids.

Depletion can also result in fractures and faults. When a res-ervoir is depleted, the pore pressure is decreased and the effectivestress increases accordingly. Depletion can cause subsidence inhigh-porosity, weak formations. It is possible that damage to therock matrix resulting from compaction could lead to the creation offractures throughout the formation. When these fractures are openand can conduct fluid, any wellbore pressure in excess of the leastprincipal stress within the formation can likely cause these frac-tures to extend, resulting in LC events. The presence of thesefractures, in effect, negates the hoop-stress concentration at theborehole wall required for pressure containment. This has beenconfirmed by Onyia (1994), who noted in the laboratory that whennotched or prefractured, wellbores have “breakdown pressures”substantially lower than predicted for intact, unfractured well-bores. Similar results, especially with oil-based mud, have beenobserved by Morita et al. (1996), who explained that the oil-basedmud does not form a thick cake, resulting in premature fluid leak-off into the pre-existing fractures.

Because of the complexity of sedimentary rocks and drillingpractice, borehole breakdown is affected by many factors. Thesefactors include Young’s modulus, borehole size, fluid properties(Morita et al. 1996), pre-existing notches or fractures (Onyia1994), borehole orientation relative to the in-situ stresses, and therock’s strength to resist fracture extension, as measured by thecritical stress-intensity factor.

Dupriest (2005) also observed that leakoff test data suggest thatthe increased hoop-stress contribution in most sedimentary forma-tions is relatively small, usually 0 to 200 pounds per square inch (psi).

The preceding discussion indicates that the process of onlysealing pores is not enough to avoid LC if hydraulically conductivefractures exist in the formation and intersect the wellbore.

The Global Petroleum Research Institute (GPRI) 2000 project(Dudley et al. 2001) focused on fracture-reopening pressure. Inthis project, fracture sealing with different particulates in mudwas investigated on 4-in. diameter core samples (Fig. 1). In thesetests, it was observed that borehole communicating with con-fining pressure occurred as soon as the fracture reopened.Therefore, the increase in confining pressure can be used to iden-tify the fracture reopening pressure. With base mud, the fracture-reopening pressure is essentially equal to the confining pressure(Fig. 2). However, when resilient graphite particulates were addedto the base mud, the fracture-reopening pressure improved sub-stantially. Fig. 3 is a test result with mud treated with resilientgraphite particulates.

Fracture Stability. So far, the “stress cage” approach analysisis based on the hydraulic-fracturing theory, and all results arerelated to hydraulic fractures, including the finite element analysisof fracture stability (Abousleimen et al. 2005). These fractures arefully inflated and therefore normally have a stress-intensity factormuch larger than its fracture toughness; which causes the fractureto propagate. However, if the fractures are not fully inflated orrelaxing, the fluid front may not extend to the fracture tip, resultingin less stress intensity at the fracture tip. Propping these “mechani-cal” fractures open away from the tip should not always damagethe system’s stability and therefore locally improve the stress be-yond the Kirsch hoop-stress range.

In examining the fracture initiation process, one can find that atthe onset of fracture initiation it takes some time for mud to flowinto the fracture. In other words, fracture initiation is not caused byfluid invasion. If the fracture is totally plugged or the fracturemouth sealed at the wellbore, before fluid penetrates into the frac-ture past the wellbore, the fracture can still be relaxed and stable.Other lab tests (Morita et al. 1996, 1990) indicate that fracturegrowth becomes suddenly unstable only when the fracture apertureexceeds a critical width to allow drilling fluid to penetrate past thewellbore into the fracture. The borehole breakdown does not oc-cur, even if an initiated fracture propagates as much as 0.3 to 3 in.The fracture-extension pressure initially increases with fracturelength before fluid starts penetrating into the fracture, which meansfractures should be sealed and propped when initiated. After be-coming inflated and ready to propagate, it is too late for pluggingwith particulates.

Again, examine the GPRI results in Fig. 3. The fracture-reopening pressure with the treated mud that achieved proper frac-ture sealing is greater than 1,600 psi, higher than twice the con-fining pressure of 500 psi, given the pore pressure of less than 100psi. This indicates that the WPC has improved to a point higherthan defined by the Kirsch hoop-stress.

These tests not only indicate that particulates play a major rolein borehole strengthening but also that WPC can be improved wellbeyond that defined by the Kirsch hoop-stress.

169June 2008 SPE Drilling & Completion

New Fracture Size Calculation for Incipient Fractures. Thedesign of special particulates to plug incipient fractures before theybecome critical and extend a significant distance from the wellborerequires estimating the fracture’s width at the wellbore wall. Afterthis width has been established, properly sized particulates can beselected to “seal” the crack. Using fracture mechanics, both thelength and width of these incipient fractures can be estimated.Fracture mechanics indicates that after a fracture has initiated, itcontinues to extend as long as the stress-intensity factor at the tipof the crack exceeds the critical stress-intensity factor or fracturetoughness of the rock.

The fracture stress-intensity factor and fracture-width equationsfor a crack with three distinct symmetrical pressurized regions arediscussed elsewhere (Deeg and Wang 2004). The same equationscan be slightly modified for calculating the stress-intensity factorand fracture width with only two pressurized regions as follows:

As a starting point for these predictions, assume the pressurewithin the borehole equals the formation breakdown pressure. Fora well perpendicular to two of the three principal in-situ stresses,

the breakdown pressure for a nonpenetrating fluid is given bythe following:

Pb = 3S2 − S1 − �Po + �tensile . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1)To estimate the length and width of the incipient crack, we

consider only the crack, neglecting the effects of the wellbore. Ifno wellbore fluids are allowed to penetrate into the portion of thecrack extending past the wellbore wall, the pressure distributionwithin the crack is as follows:

Pcrack = �Pb or Pw if Pw � Pb for x � RPo for R � x � c . . . . . . . . . . . . . . . . . . (2)

The fracture length created by this pressure distribution is cal-culated by comparing the stress-intensity factor KI for the incipientcrack to the critical stress-intensity factor KIC for the formation ofinterest. The stress-intensity factor for the previous chosen pres-sure distribution is given by the following:

KI = ��c �Po − S2� + 2�c

��Pw − Po� arcsin

R

c. . . . . . . . . (3)

Fig. 1—A 4 in.-diameter core sample for GPRI tests.

Fig. 2—Background synthetic mud shows no increase of fracture reopening pressure.


Having calculated the equilibrium crack length, the crack width atthe wellbore can be determined for the assumed crack opening-pressure distribution. It is given by the following:

w =8�1 − �2�c

�E ��

2�1 − �R

c�2

�Po − S2� + �Pw − Po� �

��1 − �R

c�2

arcsin�R

c�+ �

n=1

sin�2n arcsin�R

c��2�1 − �R

c�2

cos�2n arcsin�R

c��+R sin�2n arcsin�R

c��cn

��2n − 1��2n + 1�

(4)

Four sets of fracture width and length are calculated and displayedin Figs. 4a and 4b to show their relationships. Fracture width tendsto be larger with a longer fracture length.

Corrective Borehole StrengtheningHooke’s law states that stress is proportional to strain. When thefracture width increases, additional stress higher than Sh is inducedlocally along the propped fracture. The increase in stress observedin the near-wellbore region depends directly on fracture width. Thefluid pressure within the fracture (including the pressure distribu-tion throughout the fracture), length of the fracture, formationelastic modulus, and Poisson’s ratio determine the fracture width.Dupriest (2005) pointed out that mud losses are either cured orborehole pressure integrity is increased by improving formationclosure stress (FCS). Widening the fracture results in an increasedcompressive stress at the fracture face. This fracture face stress isthe sum of the net stress increase caused by the fracture-wideningeffect and the least principal stress, Sh. Deeg and Wang (2004)used a hydraulic-fracturing approach to study the stresses inducedby opening a slit-like hydraulic fracture, finding that the stressperpendicular to and parallel to the fracture directions (Sh and SH)becomes more compressive with increased fracture width. It is thenet stress increase higher than Sh that results in higher pressurerequired to reopen the fracture filled with sealant.

Fracture width is created by propping the fracture open. Tokeep fluid pressure away from the fracture tip, the propping ma-terial must remain immobile, and no drilling fluid should bypass orpenetrate it at the highest wellbore pressure expected. It can be

shown using basic fracture mechanics calculations that, as thecentroid of the pressure distribution within the crack or fracturemoves away from the tip and toward the center of the fracture, thepressure required to propagate the fracture increases (Deeg 1999).

Lost circulation through induced fractures is a typical Mode-Itensile failure. Increase in the tensile strength of rock can help toimprove WPC. In permeable formations, treatments that can in-crease the rock tensile strength and fracture toughness can alsocure lost circulation.

High Fluid-Loss and High Solid-Content Squeeze Pills. Forhigh solid-content, high fluid-loss particulate pills to work, thecarrying fluid must leak off so the seal can form. Fluid leakoffrequires formation permeability and a pressure differential; there-fore this treatment would hardly work in impermeable shale. Whennonaqueous drilling fluid is used, because of its superior fluid-losscontrol characteristics and relative permeability effect, such a pillmay not work well even in permeable formations, such as sand-stones, because the permeability may be damaged by the drillingfluid. This type of treatment typically works well in depleted,highly permeable formations with water-based drilling fluid. Whenconditions are different from this typical condition, treatment per-formance may not meet expectations.

Deformable, Viscous, and Cohesive Systems. When the sealbody is formed by a deformable, viscous, and cohesive (DVC)sealant, fracture width is obtained by squeeze pressure and retainedby its high gel strength. Further, these materials can deform underpressure or stress. When fracture width increases with wellborepressure, the seal body can still maintain the seal by deformingitself. It, therefore, can allow fracture width to change according tothe wellbore pressure as long as the body still remains in place,isolating the wellbore pressure. The high gel strength of the sealantrequires a high-pressure differential to dislodge the seal body,keeping it immobile. The cohesiveness of the materials can helpensure an impermeable seal body that would not allow mud topass through.

One of the advantages of the DVC system is that this treatmentdoes not depend on formation permeability to form the seal. Be-cause of the excellent fluid-loss control of oil-based mud (OBM)and synthetic-based mud (SBM), even permeable formations canbehave as if they had lower permeability in this mud environment.LC control in impermeable zones or interlayers would be difficultfor a high fluid-loss and high solid-content squeeze pill. It is some-times very difficult to know whether the loss formation is perme-able before a treatment is applied. With DVC systems, there is noneed to define whether the formation is permeable.

Fig. 3—Addition of synthetic graphite particulates substantially increased the fracture reopening pressure.


The challenge for this system occurs when (1) a large volumeof sealant must travel a long distance along the wellbore to reachthe weak zone, and (2) the squeeze pressure is limited by anotherweak formation (e.g., around the casing shoe). In this case, thematerial may not reach the zone before the pressure limitationdictates. If this is the case, a treatment can be staged into a treat-ment train, separating the treatment into discontinuous, smallersubtreatments. Although this method has been used effectively inthe field, it is often unclear when a stage treatment should be used.

Attempts during the last few decades to develop reliable DVCsystems (e.g., “gunk” squeezes) have had mixed results—workingin some cases and not in others. New DVC systems developed inthe last decade (Sweatman et al. 1997, 2001; Webb et al. 2001)have performed much better than the gunk-type systems, as evi-denced by many treatment applications in which gunk squeezesfailed to seal, followed by successful DVC system applications.

Current DVC systems have improved results in these remedial LCapplications with success rates averaging approximately 70%.DVC systems have sealing limitations and may not seal very largeleakoff flow paths into formations. For example, DVC successrates in cavernous formations, such as vugular carbonates, aretypically less than 70%. Higher success rates (up to 90%) may beseen in well applications to seal fractures or faults in competentsands and shales.

Of the several thousand DVC applications performed duringthe last nine years to reduce or halt losses, a limited number of thetreatments were applied to strengthen boreholes. The study ofthese borehole-strengthening applications in 28 wells includedonly those attempted in hole sections in which DVC limitationswere not expected to be exceeded. The success rate was found tobe 89% (25 of 28 wells). However, more than one treatment wasoften required in these wells to achieve the desired WPC. For

Fig. 4—(a) Incipient crack length for several in-situ stress–pore pressure combinations (S1,S2,Po in kpsi). Wellbore pressures ineach series are as follows: Pb,1.1Pb,1.2Pb,1.3Pb,1.4Pb,1.5Pb. (b) Incipient crack width for several in-situ stress–pore pressurecombinations (S1,S2,Po in kpsi). Wellbore pressures in each series are as follows: Pb,1.1Pb,1.2Pb,1.3Pb,1.4Pb,1.5Pb.


example, holes were deepened, exposing additional weak zones, ortoo many weak zones were present in the original hole. Fig. 5provides an example pressure-test comparison in which two DVCtreatments are needed to achieve the desired increase in WPC(Traugott et al. 2007).

The borehole-strengthening study resulted in the developmentof improved methods and materials reported in this paper. Therecently developed methods include numerical and laboratorymodels and materials, such as DVC-2, to increase WPC in wellswith a wider range of hole conditions and/or to higher WPC valuesabove the least principal stress. Fig. 6 includes pictures for dem-onstrating the forming of a DVC sealant with DVC-2 and a water-based mud.

Cement Systems. Cement has been used as an effective lost cir-culation material for long time. However, it is not a cure-all. Thereare many different cement systems. Cement slurries, in general, arethin fluids that create little pressure resistence when pumped intofractures. This low-pressure resistence would not widen the frac-ture much and therefore would incur little additional stress.However, it should be a good material for sealing vugs or opennatural fractures.

Table 2 provides a summary for the previously discussed threeapproaches that aim at improving FCS.

Strength-Enhancing Chemical Systems. In-situ polymerizationof certain chemicals, such as resin, can greatly enhance permeablerock tensile and compressive strengths. This enhancement hasbeen proven both in the lab and the field (van Oort et al. 2003,Eoff et al. 2001). This method differs from other borehole-strengthening methods, because the strengthening effect comesfrom strength improvement rather than stress.

Because the formed polymer would have an ultra-low perme-ability, formation fluid pressure and wellbore can be isolated. Thisisolation can prevent filtration through the treated zone and pre-vent pressure differential sticking. Because of the consolidationeffect, the borehole should be much more stable than before treat-ing. This method is suitable and effective for treating depletedsands and unconsolidated formations.

Permeability variation is another concern. This could causemost of the treating fluid flowing into a higher-permeability layerand leaving the rest untreated. However, if mud cake is present, itcan serve as a diverter and control a fairly even invasion of thetreatment fluid around the wellbore circumference.

It has been a concern that if the leftover chemical inside theborehole sets hard with a high compressive strength, then sidetrackmay happen while drilling out the plug.

Controlling the setting time and avoiding contamination is alsoimportant to prevent it from setting inside drill strings and casing.

This method can also be applied proactively.

Synergy of Proactive and Corrective ApproachCombinationWith the understanding of the mechanisms to increase hoop stresswith particulate-treated mud, a proactive mud program can bedesigned to drill through anticipated weak zones, such as depletedformations. The approach to improve the fracture-reopening pres-sure with DVC systems can form a corrective backup for drillingthrough uncertain formations in case of lost circulation. An im-portant improvement is that both approaches can now be custom-ized with computer programs relying on rock-based data analysis.It is also interesting that the same rock-based analysis can lay thefoundation for a proactive, corrective, borehole-strengthening jobdesign and wellbore-stability analysis.

Conclusions• Analysis with rock mechanics theory and laboratory results

shows that borehole strengthening by improving hoop stress cango well beyond the WPC defined by Kirsch hoop-stress.

• Sealing existing fractures in addition to plugging pore throats isthe key to restoring the Kirsch hoop-stress.

• For improving hoop stress with particulates, propping and plug-ging “mechanical” fractures rather than hydraulic fractures iskey to preventing fractures from becoming unstable and growingtoo long.

• For improving hoop stress with particulates, initial fracturelength and therefore the critical width at initiation can be deter-

Fig. 5—Treatment results from a DVC system.


mined by rock elastic properties, fracture toughness, in-situstresses, and borehole pressure.

• It has been proven in the field that DVC systems can improveWPC by creating a net stress higher than the existing least-principal stress in the near-wellbore region. DVC systems aredesigned to work in formations regardless of permeability.

• Combining both proactive and corrective approaches would cre-ate a beneficial synergy for borehole strengthening. Similar dataanalysis can lay the design foundation for both approaches aswell as wellbore-stability analysis.

Nomenclaturec � equivalent crack lengthE � Young’s modulus

KI � stress-intensity factorKIC � critical stress-intensity factorPb � borehole breakdown pressure

Pcrack

� pressure inside the crackPo � pore pressurePw � wellbore pressure

R � wellbore radius

S1 � larger principal total stressS2 � smaller principal total stressSh � least horizontal principal total stressSH � maximum horizontal principal total stressw � crack widthx � distance of a point inside the crack from the center of

the wellbore� � Biot’s coefficient� � Poisson’s ratio

�tensile� rock’s tensile strength

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Hong (Max) Wang is a Global Technical Advisor for Baroid FluidServices at Halliburton. Max has acquired extensive land andoffshore experience ranging from the early days of checkingmud and mixing cement in the field to his current develop-ment on fluid solutions to lost circulation and wellbore instabil-ity, with more than 20 papers on the subject published. He is aprofessional petroleum engineer. He holds a PhD degree inpetroleum engineering from the University of Wyoming and anMS degree in chemical engineering from South China Univer-sity of Technology. He is an active member of SPE, DEA, andAADE. Ron Sweatman is Chief Technical Professional in Halli-burton’s Global Business and Technical Solutions group in Hous-ton, specializing in cementing, wellbore stability/integrity, andCO2 injection technologies. Ron has served on many industryand SPE committees, published many technical articles andSPE papers, received five major industry awards, and has over25 patents. He holds degrees in chemistry from Louisiana StateUniversity and petroleum engineering from the University ofSouth Louisiana. Bob Engelman is Pressure Testing and Sam-

pling Product Manager with Halliburton Wireline & PerforatingServices. Bob holds a BS degree in mechanical engineeringdegree from the University of Colorado. He has served on SPEcommittees and has published many SPE papers and techni-cal articles. Wolfgang Deeg is currently a Staff ProductionTechnologist in Shell Oil’s Unconventional Oil group, exploringtechnologies to commercialize Colorado’s oil shale. Prior toreturning to Shell in 2005, he spent 9 years with Halliburton work-ing in stimulation, cementing, and rock mechanics R&D. Sincejoining the oil industry in 1980, he has worked on projects asdiverse as hydraulic fracture treatment design, simulation, andanalysis; designing well completions; developing models forwellbore stability analyses; implementing a waterflood andsteam drive pilot; laser perforating; and evaluating the integ-rity of a well’s cement sheath throughout the well’s life—fromplacement, through curing, and to well abandonment. He hasalso performed root-cause analyses of power generation andtransmission equipment for an electrical utility. He holds a PhDdegree in materials science and engineering from StanfordUniversity and a BS degree in mechanical engineering fromthe University of Connecticut. Donald L. Whitfill is a GlobalTechnical Advisor for Baroid Fluid Services. He holds a PhD de-gree in chemistry from the University of Oklahoma. His past SPEservice and awards include Distinguished Lecturer, 2005 and1987; Board of Directors, 1989–92; Senior Member, 2003; andDistinguished Member, 2006. Mohamed Soliman is Chief Res-ervoir Engineer with Halliburton Energy Services at its Houstoncenter. Soliman has written over 100 technical papers in areasof well-test analysis, fracturing, conformance, and numericalsimulation. He also holds 13 US patents. Soliman holds a BSdegree in petroleum engineering from Cairo University, as wellas MS and PhD degrees from Stanford University. Brian Towler isa Professor of Chemical and Petroleum Engineering at the Uni-versity of Wyoming and College of Engineering and AppliedSciences Fellow for Hydrocarbon Energy Resources. He waspreviously Department Head of Chemical and Petroleum En-gineering from 2004–2008. He is a registered Professional Petro-leum Engineer in the State of Wyoming. He holds BE and PhDdegrees in chemical engineering from the University ofQueensland in Australia. He was instrumental in setting up theQueensland section of the SPE in 1985 and was chairman ofthe section in 1988.


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