Drilling Geomechanics - Pre-Drill Fracture Centroid Perspective is Key to Spot Casing Setting Depths and Trajectories at High Risk for Ballooning

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Drilling Geomechanics – Pre-Drill Fracture Centroid Perspective Is Key To SpotCasing Setting Depths and Trajectories At High Risk For Ballooning.

Michael Davis, SPE, Drill Science Corp.

AbstractDrilling geomechanics offers perspectives onissues we face in drilling and constructingwellbores that are helpful in preparing plans thatsuccessfully model actual downhole conditionsprior to drilling in. Several particular issues havebeen inadequately addressed and commonlydeemed to be unpredictable by industry experts.These particular events, specifically loss/gainphenomena, and the ability to predict andexplain various nuances have not beenadequately explained in the world ofgeomechanics. Since the statistics kept by wellcontrol companies show that wrong assumptionson loss/gain events and otherwisemisinterpreting or miscommunicating well control

events account for a great percentage ofresulting blowouts, the importance of this topic isclear. The procedures for dealing with theseissues are better discussed in full prior tospudding the well, yet up until now there wereno methods for predicting ballooning in advance.Drilling margins in wells being very small,misdiagnosis can lead to unnecessary wellcontrol procedures that can be very costly andlead to many hours of non-productive time(NPT). Even worse are instances in which areal kick is misdiagnosed as ballooning and thewell is allowed to flowback leading to an

increase in kick volume and shut-in pressures.

For years it has been observed that drilling inand around certain conditions one can expectballooning. In hindsight the particular situationscan be seen and a paradigm created. Withinthis paradigm it can be seen that, for particularin-situ stresses, magnitudes, structures, andlocalized peculiarities, patterns emerge thatmight suggest a predictable set of

circumstances that lead to ballooning. The mostvital element of predicting ballooning issues inthe pre-drill planning phase is to utilizeseismically identifiable stress features such asfaults, folds and bright spots to imply stressmagnitudes and directions. This is in essencederiving present stress information from paststrain seismically recorded as deformation fromreflected seismic interpretation packages. Thesignificance of such structures and stresses thatare clearly indicated in seismic records are vitalto the methods outlined by this paper.

This paper addresses the issue of ballooning indrilling and gives a geomechanical explanationand means for predicting and mitigating the

issues that will be confronted during the drillingphase of well construction wherever possible. Itis my belief that in doing so communicating ininterdisciplinary teams and conveying issuesand instructions between the rig and the officewill be greatly enhanced. The result shouldsave time in diagnosing the problems and inimplementing the solutions and also result inmuch safer operations.

In most cases ballooning can be predicted forany trajectory and casing setting depth designusing the concept of the “Fracture Centroid”

(FC) (Davis 2011c) and an alternative trajectoryand/or casing setting depth designed that willavoid the worst conditions or eliminate theballooning entirely. If this is concept is used andproven to prevent wellbores with extremely highrisk of ballooning, these screening and designmethods will be responsible for eliminating oneof the most, if not the most significant, causes ofwell control incidents and NPT in the industry.



IntroductionThe phenomenon of “ballooning”, “breathing”,“loss/gain” or “wellbore storage”, will heretoforebe simply referred to as “ballooning”. Withacknowledgement to all previous documentedarguments to this being a misnomer and alsothe fact that more often than not, people on therig and in the office do speak of this phenomenaas “ballooning”. Complicating factors beingobserved in the field are: losses with incompleteflowback, complete losses and no flowback,losses and flowback during trips and not duringconnections, losses and flowbacks exceedinglosses, losses of mud and flowbacks of gas, etc.The list is seemingly endless yet I will constructa matrix and list explanations and layman’sterms of many of the most commonlyexperienced phenomenon below.

First, let’s examine a scenario common to many

of the most common petroleum traps drilledtoday that can and will balloon if penetrated.Most instances can be predicted and avoided bydiligent scrutiny as to the structure, the pressurecompartments and imbalances that can bequickly and easily deduced. Both pressures andstresses in the sands and shales that areinvolved in a ballooning wellbore can besurmised with the clever use of seismicallyobtainable information. As stated earlier it ispossible to detect wellbores that will balloonbefore drilling by using seismically attainabledata and therefore it is possible to avoid these

scenarios even in wildcat wellbores. Thecontent of the reservoir fluids is vital to theanalysis and the prediction of sand contents isn’talways guaranteed as we all know. Even ifreservoir contents can’t be absolutelyascertained a screening for possible ballooningconditions based on a worst and best case caneasily be made.

Structural apex penetrations of strata withsand/shale sequences where the sand porepressures are much higher than the boundingshale pore pressures have a high potential to

balloon. This same environment tends to havesand fracture strengths exceeding the shalefracture strength by an appreciable amount.The drilling fluid equivalent static density (ESD)will necessarily be higher than the highestexposed sand reservoir pressure or else the wellwill kick during connections. The only remainingfactor needed for ballooning is a sealingboundary that prevents fractures that form in theshales from extending indefinitely allowing the

fracturing fluid to leak off. The amount ofpressure by which the shale fracture pressureexceeds the highest exposed sand porepressure is the margin that a drilling operationmust work between. Let’s call this theballooning threshold (BT):

BT = ……………………..(1)

The overbalance margin of the drilling mud overthe highest sand pore pressure, the equivalentcirculating density (ECD) with the rig pumping atfull rate and equivalent annular density oncedrilling at full rate of penetration (ROP) beginswill determine if the wellbore balloons.

Complications of Ballooning PhenomenaA quick matrix of the most commonlyexperienced ballooning phenomena and therelations that determine these follows. For all ofthe following relations it is assumed that thewellbore penetrates the strata in an above FCposition so:

ESD ≥

and therefore the well will not kick as long asthere is no swab pressure applied and the wellwill not lose mud unless there is a surgepressure applied. This is by definition theconditions as they exist in a ballooning wellbore

environment. The matrix is:

No losses with pumps off:

ESD -

-

ESD

Losses as pumprate is increased before fullcirculation rate reached with incompleteflowback (partial ballooning):

-

BT ECD -

ECD

Losses as pumprate is increased before fullcirculation rate reached. Full volume lost isreturned during connections or when pumpsstopped (ballooning):

-

ECD - BT

ECD ≥



Losses only after full circulation rate and drillingbegins with incomplete flowback (drilling withpartial ballooning):

-

EAD -

EAD

ECD

Losses only after full circulation rate and drillingbegins with complete flowback (drilling withballooning):

-

EAD - BT

EAD ≥

ECD

Losses only after full circulation rate and drillingbegins with total losses at full ROP andincomplete flowback (control drilling withballooning):

EAD - BT

-

EAD

ECD

There are other fine nuances of scenarios notdescribed in this matrix and yet this probablycovers the most commonly found. Anothercommon scenario that happens is that the ESDis increased due to increasing signs of adecreased margin until, during circulatingaround the increase, partial returns are lost.The circulation rate is reduced and yet once thehigher density mud is completely circulated

around the wellbore is losing mud slowly. Upontripping out of the hole and reducing the ESD bythe swab pressure of pulling the drillstring frombottom, the well is ballooning back mud. This isvery dangerous and needs to be understood.The matrix relations follow:

EAD≤ECD≤

≥ - ≥

This scenario is not dangerous unless:

- ≤

The problem is if there is mud ballooning backduring a trip out of the hole it is necessary andyet obvious to determine which of the followingis true:

A kick is being swabbed into the wellbore:

- ≤

The wellbore is ballooning:

-

Another quick note is to warn that sometimes ashale will balloon immediately below a sand.

Once wellbore pressures are brought backbelow the shale fracture pressure the shalefracture closes and yet pushes the fluid at theboundary of the sand above it with enoughpressure to cause the gas in the sand to beforced into the wellbore. Of course then the gasexpands upon nearing the surface and it seemsto be a real kick and yet once the balloonrelieves its pressure and the gas clears the floorthe well is dead. This is difficult to understandas it is happening and yet if you have the kind ofunderstanding and knowledge that we arediscussing in this paper you will be betterequipped to notice such nuances and distinguishbetween ballooning and actual well controlevents better.

The anatomy of a ballooning wellboreHow much volume will be stored in fractures,how much, if any will be lost? How much will bereturned to the wellbore and what the shut incasing pressure will be if the rig crew shuts thewell in? This all can easily be determined pre-drill using the details of the informationdiscussed in the previous section. Many timescrews shut-in the ballooning wellbore confusingit with a possible kick. Pressure While Drilling

(PWD) tools can be analyzed and a ballooningwellbore (Zoback 2007) diagnosed quickly bynoting a gradual decrease in pressure whenpumping is stopped and a correspondinggradual increase in pressure when pumpingresumes. Of course without a PWD anexperienced rig crew might, know or beinstructed to, let a wellbore suspected ofballooning flow back into a 5 gallon bucket andnote the time it takes to fill and then determine itis a balloon if the time gradually increases. Allof the details of how to handle and analyzesurface indications of ballooning will not be

discussed further here although it is a worthysubject for discussion. The discussion belowwill focus on the geomechanical explanationsand pre-drill methods to spot and avoid theworst subsurface positions for encounteringthese dangerous phenomena.

All of these details can be predicted with theknowledge and understanding of geologicalstructures and resultant stresses, seismically



attained material properties, formation water andpetroleum fluid hydraulics, and the ESD, ECD,EAD, and swab/surges of the fluid circulationsystems on the drilling rig. Geomechanicalprinciples along with the concept of FC explainthe phenomena of a ballooning wellbore.

Through experience drilling in areas that balloonI have come to understand that ballooning issymptomatic of shales that fracture and yet can’t“absorb” the drilling fluids because the shalesare porous yet not so permeable below a certaindepth. Normal losses where the sands andshales or only the sands fracture, are differentbecause the fluid entering the sands becomestrapped in the high porosity and permeabilityand the fluids are “absorbed” into the sandporosity once the fracture closes as wellborepressure is reduced.

Figure 1—Log section showing indicationsof “normal” losses of drilling mud in sands.

This is distinct from the ballooning scenariowhere the fluid is not “absorbed” and is forcedback into the wellbore as the fracture wedgecloses and the fluid has no place to go except toreturn to the wellbore from where it came. Therelation for this non-ballooning section is:

This wellbore section is by definition below theFC.

Figure 2—Log section showing indicationsof “ballooning” of drilling mud in shales

The task of this paper is to predict where theseconditions exist in the earliest stages of a projectso that wellbore trajectories that will drill inballooning conditions can be avoided or in caseswhere they can’t, be drilled with tactics,strategies and plans that will not result insubstantial lost time nor unacceptable risks.

Figure 3—Another example of ballooningshales

The relation for these ballooning sections is:

This wellbore section is by definition above theFC.



Where do ballooning formations exist andwhy? As introduced before wellbores drilled throughhighly dipping formations encounter highpressure sands bounded by shales of lower porepressure at the above centroid apex of thestructure because of sand pressure buoyancyeffects.

Figure 4—Bouyancy effect resulting in high

updip sand pressures.

The pressure imbalances can be explained bythe centroid effect that has been welldocumented in the literature and most recentlyby Heppard and Traugott (Heppard 1998).

Sand

pressure, in the above pressure centroid (PC)sections of a contiguous sand, is of higherpressure than the bounding shales. The abovePC sands are of higher pressure than thebounding shales and increasingly so as theheight above the PC increases. The increasedfracture gradient in these sands is the result of

increased pressure due to the structure of thesand/shale sequence, its resultant structural andporoelastic stress disequilibrium, and its elasticproperties. The FC was discussed in depth in aprevious paper (Davis 2011c). It was discussedthat above the FC the sand fracture strength ishigher than the bounding shales. In certainsituations the sand fracture pressure will be sohigh as to completely deny a shale fracturingdrilling fluid any exit from the fractured shale

other than to return mostly back into thewellbore and thus balloon. There is anotherfactor that further increases sand fracturepressures relative to the fracture pressures ofthe bounding shales. This is the reinforcing andincreasing of the minimum principal stress in thesand relative to that of the shale in these abovecentroid geologic structure positions. The causecan be simply illustrated by analogy. Considerthe sands as being stiff like steel plates and theshales “rubbery” as rubber plates. If the platesare horizontal:

Figure 5—Sands and shales have differentelastic properties and thus different effectivestress.

Because of overburden and the Poisson’s Ratio() of formations, a vertical load is translated intohorizontal stresses. Because the of zones is afunction of composition and sands typically havelower values than shales the shales typicallyhave higher fracture strengths than sands as afunction of depth according to “bi-lateralconstraint” theories used in the past. The Tri-Lateral Compaction (TLC) theory explained in anearlier paper (Davis 2011a) rejects the “bi-lateralconstraint” methods of fracture gradientprediction because of its failure to correctly

model increasing fractures strengths seen indeeper wells. The TLC theory corrects for thisby acknowledging that there is a general strainas a function of depth model and this strain hasa more severe effect on zones with highestYoung’s Modulus (E). This is seen by inspectionof the basic TLC equation in a relaxed basin:

+

….(2)



An increased effective stress in the sands of ahighly dipping reservoir scenario is due to theload of overburden being increasingly supportedby the more rigid sands (higher E). The sandsact like columns supporting the overburden loadfrom acting on the shales. This scenario thoughextreme is often seen in modern petroleumtraps, especially those of salt trapped flanksands of deepwater, extensional basins aroundthe world. Because of the load beingincreasingly supported by the sands, theeffective stress in the shales is furtherdiminished causing the fracture gradients in theshales to decrease relative to the sands. This isa simplistic argument and yet it holds up under amore rigorous and detailed inspection. Ofcourse the reality is that the sands and shalesare rarely vertical yet explained by the principlesof statics, the stresses and fracture pressures ofthe sands go up to a maximum at vertical and

the stresses and fracture pressures, in theshales go down to a minimum. Of course this isin addition to the increase in sand/shale fractureratio seen due to TLC strain of equation 2.

Figure 6—Tilted sands act as supportcolumns effectively changing in-situ stressstates.

Stress is increased in the sands relative to theshales, as they tilt toward 90°, because thesands being more rigid they take more of theload away from the shales. The stress states ofthe sands and shales as a function of thestructural geometries are complex and it is notthe task of this paper to go into the depths ofthese complexities. The point of this illustrationand this paper is to know that in the case oftilted reservoirs, the conditions for ballooningexist from a pressure and stress condition found

in the above centroid wellbore positions. Fromthe example it is clear that highly dipping bedstend to increase sand fracture strengths relativeto the bounding shales. The followingdiscussion will demonstrate how to accuratelymodel the stresses in these scenarios.

The use of dip angles to compensate for theseeffects is possible due to a general knowledge ofstrain in the horizontal plane and was introducedin the TLC equation (Davis 2011a):

+

+

…………………(3)

Most wellbores target sands in above centroid

structural positions. In these structural positionsthe sand reservoir pressure is above thebounding shale pore pressure by definition. Thesands require raising the drilling fluids density toa hydraulic pressure above the sand porepressure to keep the reservoir fluid from enteringthe wellbore according to well control principles.The higher up on the structure the sand is drilledthe higher the reservoir pressure will be relativeto the shale pore pressures. Extreme apexwellbores exceed the shale pore pressures andif above the FC they very easily exceed theshale fracture pressure. In this scenario theshale fractures and the sand won’t.

Figure 7—example of above and below FCconditions. Red→yellow horizontal gradientbars are from FC to min or max.





Figure 9---Elastic Chamber

These bounds form essentially elastic chamberswhere fluid can be elastically stored and yet notreleased to be absorbed and lost completely.As we can see these conditions are required forballooning to happen. Note that in these highlydipping reservoirs the sand Pp upper limit canreach the shale Pf and exceed it to the fracturepropagation pressure of the shale. Also notethat as the fracture fills with more drilling fluidthe fracture width increases. The pressure topropagate the fracture in the shale will increaseas the fracture width increases because theheight and length of the fracture is limited by thehigh Pp and Pf of bounding sands. Many ofthese shales are “charged” up dip and upstructure and are bounded by above FC sanddown dip and increasing Pf shale downstructure. In this example an elastic chamberthusly exists and the size of this chamberdetermines the volume and characteristics of theballooning. As the fracture builds the volume oflosses diminishes because the pressure topropagate the fracture increases. Once thefracture tip reaches an unfracturable boundaryat a high Pp and Pf bounding sand and updipcharged shale zone and an increasing shale Pf

down structure, the fracture length and heightcan no longer grow and only the fracture widthmay increase. The increasing fracture widthrequires increasing pressure to open further. Asthe balloon is allowed to flow back into thewellbore the opposite is seen. Initially thepressure and flowrate into the wellbore is highand it gradually diminishes as the fracture lengthand width closes in. If a wellbore penetrates an

elastic chamber thus described the shale mayimmediately fracture and the wellbore fluid willfill these fractures until the shale Pf + fracturepropagation pressure equals the pressureexerted by the drilling fluid in the wellbore at thetime. The volume of ballooning fluid may thenbe estimated by the following relation:

………………..…………………(4)

Where:

Another fracture barrier comprising the elasticchamber of the example that hasn’t beendiscussed yet is the stress that keeps thefractures from growing in the lateral directionalong the bedding planes. This can be

explained by keeping in mind that fractures willform in the direction of the maximum principalstress. In the case of highly dipping sandsagainst a salt trap it is well known and mostlyunderstood that the maximum horizontal stressradiates outward compressive stresses from theface of the salt. This will cause the fractures toorient and grow directly toward and away fromthe salt and so makes our two dimensionaldiagram accurate in portraying that there is nofracturing in the direction of the third dimension.Similarly, most highly dipping sands, whetherthey terminate into a salt face or up against afault trap have an increased horizontal stresscomponent normal to the strike of the fault at theproximal apex sections of the shale, and in thedirection of the apex. This is due to thehorizontal stress added by the deflection ofoverburden stress normal to the fault plane.This radiates outward of the fault trap similar tothe outward compressive stress adjacent to saltfaces. The description of these stresses and themechanics of the fractures opening and closingare generic. There are variations on this generalscenario, yet the basis of all of these variationsmust meet the specific criteria discussed above.There can be much detailed work done to

determine fracture propagation pressures,fracture width, and anticipated fracture heightthat can model with precision the exactpressures to expect and volumes to be involvedif a ballooning environment must be drilledthrough or is unexpectedly encountered. Thesedeterminations vary little from the analysis thatgoes into the pre-planning of a shale fracturestimulation job.



SummaryThis paper addressed the issue of ballooning indrilling and gave a geomechanical explanationand means for understanding, predicting andmitigating the issues. It is my belief that in betterunderstanding the phenomena of ballooningcommunicating in interdisciplinary teams andconveying issues and instructions between therig and the office will be greatly enhanced. Theresult should save time in diagnosing theproblems and in implementing the solutions andalso result in much safer operations and betterplans. In most cases ballooning can bepredicted for any trajectory and casing settingdepth design using the concept of the FC and an

alternative trajectory and/or casing setting depthdesigned that will avoid the worst conditions oreliminate the ballooning entirely. By changingthe trajectory and/or casing setting depths thewell designer may place wellbore locations inadvantageous positions relative to the PC andFC. If this concept is used to prevent wellboreswith extremely high risk of ballooning, thesescreening and design methods will beresponsible for eliminating one of the most, if notthe most significant, causes of well controlincidents and NPT in the industry.

Nomenclature = poroelastic coefficientBT = Ballooning Threshold =

= depth at which the vertical stress is maximum for the total interval planned to be drilled.

= depth of interest∆= reduction of bottom hole pressure in a wellbore due to swabbing effect of pulling pipe. Young’s Modulus aka Elastic Modulus = strain in the direction of maximum horizontal stress tectonic & tri-lateral compaction (TLC) strain in the direction of maximum horizontal stress tectonic & tri-lateral compaction (TLC)EAD = equivalent annular density includes the added weight of circulating mud and cuttings load. = equivalent annular density while control drilling at reduced ROP to minimize losses. ECD = equivalent circulating density includes the friction pressure of the circulating mud system.

ESD = equivalent static density of the pressure a drilling fluid column exerts at the hole bottom.FC = fracture centroid depth PC = pressure centroid depth = fracture pressure

= fracture pressure of a sand

= pore pressure

Minimum fracture pressure of all sands in any open hole interval

Minimum fracture pressure of all shale in any open hole interval

= Maximum of all sand pore pressures in any open hole interval

= radius of the earth ~ 20,903,520 ft

minimum horizontal stress in a normal faulting regime overburden stressTLC = Tri-Lateral Compaction equation

+

+

= Poisson’s Ratio



ReferencesDavis, M. D., 2011a, Basis Change Enables Better Fracture Pressure Prediction Via OnlySeismic Data, SPE (submitted December 4, 2011)

Davis, M. D., 2011b, Best Practices in Selecting Casing Setting Depths and Common DesignPitfalls, SPE (submitted November 3, 2011)

Davis, M. D., 2011c, Drilling Geomechanics - Pre-Drill Fracture Centroid Perspective Is KeyTo Design Pressure Balanced Open Hole Intervals And Avoid Costly Imbalances, SPE(submitted December 25, 2011)

Heppard, P. D., and Traugott, Martin O., 1998, Use of Seal, Structural, and CentroidInformation in Pore Pressure Prediction in Alan Huffman, ed., Transactions of the AmericanAssociation of Drilling Engineers Industry Forum, Pressure Regimes in Sedimentary Basinsand Their Prediction, September 2 – 4, 1998, Conroe, Texas p. 4

Zoback, M. D., 2007. Reservoir Geomechanics, first edition. Cambridge University Press.

Author BioMichael Davis is a petroleum engineer with Drill Science Corporation in Houston consulting for operatorswith operations worldwide. Davis has engineered and managed drilling and completion projects with majormultinationals and independents, mostly in HTHP and deepwater environments as well as drillingintervention wells and other highly technical projects needing his expertise and leadership. Davis researchesemerging technologies and the science and psychology of team building and team work. Davis values thepeople involved in a project as the greatest resource and believes the tools and skills required for thesepeople to excel is key. Davis holds a Bachelor of Science degree from the University of Texas in petroleumengineering. Davis is a Member and Technical Editor for the Society of Petroleum Engineers' EditorialReview Committee as well as a frequent participant and contributor to the Drilling and Geomechanics TIG onthe SPE.org website.

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Drilling Geomechanics - Pre-Drill Fracture Centroid Perspective is Key to Spot Casing Setting Depths and Trajectories at High Risk for Ballooning