SPE-170263-MS

Wellbore Strengthening in Sandstones by Means of Nanoparticle-BasedDrilling Fluids

Oscar Contreras, Chevron Canada, University of Calgary; Geir Hareland, Oklahoma State University;Maen Husein, University of Calgary; Runar Nygaard and Mortadha Alsaba, Missouri University of Science andTechnology

Copyright 2014, Society of Petroleum Engineers

This paper was prepared for presentation at the SPE Deepwater Drilling and Completions Conference held in Galveston, Texas, USA, 10–11 September 2014.

This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contentsof the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflectany position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the writtenconsent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations maynot be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.

Abstract

Drilling operations of both conventional and unconventional oil and gas accumulations are becomingmore challenging especially in deep-water operations. Due to the narrow mud weight window in offshorewells, a proper wellbore stability analysis is required for a cost-effective execution. Wellbore strength-ening is an approach used to increase the fracture pressure of the rock, widen the mud window andconsequently enhance the well integrity and mitigate mud losses. This paper demonstrates the feasibilityof wellbore strengthening in permeable formations using oil-based mud (OBM) containing in-houseprepared nanoparticles (NPs) combined with graphite. A significant increase in the fracture pressure wasachieved and the predominant wellbore strengthening mechanism was identified.

Fracture pressure increase was quantified by carrying out hydraulic fracturing tests on 5 3/4��9�Roubidoux sandstone cores. A 9/16� wellbore was drilled, cased and cemented to simulate well condi-tions. Overburden and confining pressure were applied on the cores while testing to simulate a normal-faulting regime. Two injection cycles were applied allowing 10 minutes of fracture healing between thecycles. The fracture pressure was increased by 65% when calcium-based NPs (NP2) blends were used,whereas it increased by 39% in the presence of iron-based NPs (NP1). Optimum NPs concentrations wereestablished after a comprehensive experimental screening. A strong relationship between wellborestrengthening and mud filtration at high-pressure high-temperature (HPHT) using a filter press on ceramicdiscs was found. Optical microscopy, scanning electron microscope (SEM) and energy dispersive X-rayspectroscopy (EDX) analyses were conducted on the hydraulically fractured cores. The fractures wereseen to be completely sealed from tip to wellbore. Therefore, tip isolation by the development of animmobile mass was identified as the predominant wellbore strengthening mechanism. A 40 micron-sealcontaining homogeneously dispersed NPs and graphite was observed. In addition, a 300 micron-filter cakewas developed around the wellbore also containing homogeneously dispersed NPs.

IntroductionDrilling a well confirms the presence of hydrocarbons in a reservoir and enables the first productionforecast. This practice accounts for high expenditures in the complete exploration and production

portfolio. Drilling operations are currently facing new challenges when exploring unconventional andconventional oil and gas accumulations onshore and offshore. Execution of these operations at the lowestcost while meeting environmental standards is a requirement, which instigates the development of newtechnologies. The most common drilling problems include formation damage due to mud filtration, lostcirculation, narrow mud windows, and wellbore instability. These problems can yield to a significantincrease of the total drilling cost and sometimes are the cause of sidetracks operations, well abandonmentor eventual blowouts. All these problems can be addressed by wellbore strengthening. Wellbore strength-ening is the practice that increases the fracture pressure of the rock and has been studied since the 1980’s(Withfill and Nance 2008); however, a generalized theory of the actual mechanism that causes the fracturepressure increase is not fully understood. While some schools of thought argue that this phenomenon isonly possible in permeable formations, others believe that this can even take place in impermeableformations. The possibility of the simultaneous occurrence of multiple wellbore strengthening mecha-nisms is also a topic of discussion as well as its relationship with the mud filtration. At this instance somequestions arise related to wellbore strengthening: what is the predominant mechanism? Can NPs serve asa wellbore strengthening agent? Is there a relationship between wellbore strengthening and mud filtration?What type of NPs are the best? What is the optimum concentration of NPs for this purpose?. This paperpresents an experimental research to answer the previous questions based on hydraulic fracturing tests,optical microscopy, SEM, and EDX analyses. Details on the mud filtration data at API HPHT (500 psi& 250°F) on ceramic discs used in this paper can be found in a previous publication (Contreras et al. 2014)that was conducted as an earlier research stage. The used blends nomenclature was the same for the easeof understanding.

NPs Applications in Drilling IndustryParticles used in drilling fluids with a size between 1-100 nm are called NPs (Amanullah and Al-Tahini2009; Zakaria et al. 2012; Hoelscher et al. 2012). The application of NPs in the petroleum industry becamesignificantly popular in different disciplines and is capturing the attention of operators. Several applica-tions of NPs in drilling industry have been reported in the literature. Applications in wellbore strength-ening (Contreras 2014; Nwaoji 2012), mud filtration control (Contreras et al. 2014; Cai et al. 2012;Zakaria et al. 2012; Srivatsa et al. 2011; Javeri et al. 2011; Sensoy et al. 2009), wellbore stability (Rileyet al. 2012; Li et al. 2012; Hoelscher et al. 2012), torque and drag (Hareland et al. 2012), mitigation ofpipe sticking (Javeri et al. 2011), and drilling and production into HPHT conditions (Nguyen et al. 2012;Singh and Ahmed 2010). These very small particles can have access to the smallest pores and are also ableto seal pore throats even in very-low permeability formations. Figure 1 illustrates the effect of NPs whenthey are combined with conventional lost circulation material (LCM). When only LCM is added to the

Figure 1—Mud filtration using (a) only conventional LCM and (b) NPs and conventional LCM (Contreras 2014).

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mud, higher particles invasion occurs (Figure 1a) asa result of a loose filtercake. NPs fill in the gapsbetween the bigger particles creating an effectiveseal and, subsequently, preventing particle invasionto the porous media (Figure 1b). NPs are also be-lieved to interact with clay particles participating atthe initial stage of the filter cake formation creatinga thin and very low permeability cake (Zakaria2013). Due to their ability to form thin, non-erodibleand impermeable filter cake, NPs are considered apowerful additive in reducing mud filtration.

Review of Key Aspects of PublishedWellbore Strengthening ApproachesKey aspects from wellbore strengthening investigations published in literature are highlighted focusingparticularly on those directly related to the results obtained in this paper. Other aspects can be foundelsewhere (Contreras 2014; van Oort et al. 2011). Wellbore strengthening was initially studied experi-mentally in the 1980s by the DEA-13 project (Fuh et al. 1992; Morita et al. 1990; Black 1986). Differentfluids and concentrations were tested for fracturing tests and fluid loss measurements. Reopeningpressures were observed to be higher in the presence of water based mud (WBM) as compared to OBMdespite experiencing a similar fracture breakdown pressure. This phenomenon was explained by the effectof the filter cake and amount of filtrate going into the formation. Analysis on DEA-13 project alsoreported the occurrence of peak shapes in the pressure behavior versus time when utilizing WBM.Researchers believed that the screen out generated a complete fracture sealing requiring a higher pressurelevel in order to go through to the current fracture tip. It was also stated that more unstable fracturepropagation took place on low permeability formations due to the buildup of weaker filter cakes. Later on,the GPRI joint industry project (Dudley et al. 2001) was accomplished trying to replicate the DEA-13experimental work. From these studies, the first insights into the wellbore strengthening mechanism weremade and served as the basis for the current schools of thought that try to explain the wellborestrengthening mechanism. Graphite was found to be a convenient wellbore strengthening agent. Currently,the drilling industry converges mainly on two wellbore strengthening mechanisms: tip resistance by thedevelopment of an immobile mass (Dupriest 2005) and stress caging theory (Alberty and Mclean 2004;Aston et al. 2004). Nevertheless, another mechanism called fracture propagation resistance (FPR), whichis also built on the basic principles of the DEA-13 and GPRI projects has been recently introduced (vanOort and Razavi 2014; van Oort et al. 2011). More details on the three mechanisms are presented below.

Tip Resistance by the Development of an Immobile MassDupriest (1995) presented fracture closure stress practices where the fracture was blocked by particles sothat the pressure was not transmitted to the tip. In this instance, the fracture width plays a crucial role asit might be widen when additional pressure is applied in the wellbore and the blocking material isbypassed. When LCM is driven into the fracture, it is believed that an immobile mass can isolate thefracture tip due to the loss (mud filtrate) of its carrier fluid to the formation. Initially there is low resistanceto flow into the fracture, however if resistance occurs the back pressure widens the fracture. This elasticgrowth of fracture width regulates the build-up pressure. This phenomenon is represented graphically inFigure 2. As the fracture is packed back to the wellbore, higher wellbore pressure values are required tocontinue the fracture extension, which causes wellbore strengthening. Difficulties in the creation of theimmobile mass by particles are believed to occur in very-low permeability formations as the mechanismrequires some leak-off. Nevertheless, some material can invade induced and widened fractures in

Figure 2—Tip resistance by the development of an immobile mass(Contreras 2014).

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impermeable media as this paper will discuss lateron. This wellbore strengthening mechanism doesnot require modeling of the LCM strength and type;these were found as non-important parameters forthe tip isolation.

Stress CagingThe stress caging theory has been studied by differ-ent researchers (Wang et al. 2009; Wang et al. 2008;Soroush and Sampaio 2006; Song and Rojas 2006;Aston et al. 2004; Alberty and McLean 2004). Thefundamental principle of the stress caging corre-sponds to the deposit of solids at or close to thefracture mouth to act as both proppant and sealisolating the fluid pressure. Considering a suffi-ciently permeable formation, the filtrate beyond theblockage will dissipate and pressure in the isolatedpart of the fracture will reach the same value of thepore pressure and, subsequently, the fracture willclose. An increase in the hoop stress is generatedwhen the fracture closes due to the blockage (orbridge) compression. Figure 3 shows a schematic ofthe stress caging mechanism.

Stress caging has also been reported to be the wellbore strengthening mechanism in shale formations(Aston et al. 2007). This approach is based on the transportation of bridging particles that could act as“cement” into the fracture. The solidification will avoid seapage and flow back towards the wellbore.From the stress caging theory, a mathematical summary is developed by the authors of this paper in orderto capture the physical phenomenon. Assuming that at t�0 the fracture was created, then at t�t1: time atwhich the fracture is propagating in the far field stress region, i.e., region with no effect of hoop stress,we have:

Eq. 1

where Pf1 is the pressure of the fluid into the fracture at t�t1, Pw1 is the pressure in the wellbore at t�t1,�h’ is the effective in-situ horizontal stress and Po1 is the pore pressure at t�t1. At t�t2: time at whichthe fracture stops growing we have:

Eq. 2

where Pf2 is the pressure of the fluid into the fracture at t�t2, Pw2 is the pressure in the wellbore at t�t2,and Po2 is the pore pressure at t�t2. At t�t3: time at which the fracture starts closing we have:

Eq. 3

where Pf3 is the pressure of the fluid into the fracture at t�t3, Pw3 is the pressure in the wellbore at t�t3,and Po3 is the pore pressure at t�t3. Numerical studies (Salehi and Nygaard 2012; Salehi 2011) on thestress caging mechanism showed that wellbore hoop stress after wellbore strengthening did not exceedideal hoop stress for the intact wellbore arguing just a fracture gradient restoration. This means that thestress caging is described as an ideal mechanism that will not take place in real field conditions. Also,explicit and comprehensive experimental evidence that confirms the occurrence of the stress caging hasnot been published up to now (van Oort et al. 2011).

Figure 3—Stress caging (Contreras 2014).

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Fracture Propagation Resistance (FPR)FPR aims to increase just the fracture-propagation pressure by means of tip-isolation using specificparticulate additives (van Oort et al. 2011). This opposes the underlying theory behind the tip resistanceand stress caging mechanisms that requires an increase in the fracture initiation pressure (FIP) (van Oortet al. 2011). FPR proponents argue that the stress caging or fracture tip resistance should increase the FIPor leak-off point (LOP). In other words, an extension of the linear part in the pressure (P) vs. time (t) plotresulting from a leak-off test (LOT) should be noticed. In contrast, if FPR was the wellbore strengtheningmechanism, no increase in FIP should be observed before or after the treatment as illustrated in Figure 4.This figure, however, may be not explicit enough since both mechanisms, tip resistance and stress caging,require the creation of a fracture as a prerequisite. van Oort and Razavi (2014) showed evidence that theFIP did not increase after a wellbore strengthening treatment and therefore FPR was believed to be thepredominant mechanism. This conclusion was not based on their own designed experiments in rocksamples, but rather based on analysis of previously published data from the DEA-13 project, stress caging,and fracture closure stress (Dupriest 2005; Aston et al. 2004).

In this paper, experimental evidence and new data may contradict to some extent the underlininghypothesis of the FPR mechanism. The FIP was observed to increase after a particular blend containingNPs and LCM was prepared and tested for wellbore strengthening. This fact implies that the conditionillustrated in Figure 4a is possible as opposed to the van Oort and Razavi (2014) analysis.

Other Recent Works on Wellbore Strengthening and Additional Wellbore StrengtheningMechanismsSalehi (2011) performed a numerical simulation of fracture propagation and sealing on the wellbore andtheir implications in wellbore strengthening. Three-dimensional poro-elastic finite element simulationswere conducted to simulate fracture initiation, propagation and sealing. A methodology for fractureinitialization based on non-linear behavior was conducted using cohesive modeling. This author arguesthat wellbore strengthening is only able to cause hoop stress restoration, but it is not able to increase thehoop stress over its ideal or original maximum value defined by the Kirsch (1898) analytical solution.Mostafavi (2011) developed an experimental analysis and mechanistic modeling of wellbore strengthen-ing. Resilient graphite was identified as the material that provides the best performance for wellborestrengthening from core fracturing and reopening experiments. A critical particles concentration into thedrilling fluid was established. Beyond this concentration the strengthening process was not improved. Thiswork only considered conventional LCM. Also, the tests were not conducted in real rock samples. Thismay limit the extrapolation from this idealistic model to real field operations. Later, Nwaoji (2012)

Figure 4—(a) Idealized LOT response that indicates a near wellbore stress change that should result from stress caging or fracture tip resistance.(b) Idealized LOT response after FPR (van Oort et al. 2011).

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performed experimental research on wellbore strengthening involving ex-situ prepared NPs mainly inWBM systems. A maximum breakdown pressure increase of 70.31% was obtained using WBM imper-meable cores. The WBM tested was not commercial; it was just composed of water and bentonite. OBMwas also involved in the testing and a maximum breakdown pressure increase of 36.39% was achieved.The wellbore strengthening mechanism was not addressed. Overall, the WBM performed better than theOBM. Filtration tests on these blends were not conducted and this was a limitation of this work. Graphiteexhibited superior strengthening characteristics in comparison to calcium carbonate. However, blendscontaining just graphite (with no NPs) were not analyzed to quantify the effect that NPs have over theLCM. This means that the positive effect (if any) of NPs on wellbore strengthening was not quantified.Few tests were run in concrete cores simulating impermeable media and some degree of strengthening wasachieved. While a concrete core can simulate an impermeable media, it cannot be compared with shaleformation. Shale formations have different mechanical properties compared to concrete. Also, shaleformations are sensitive to air and water contact while the concrete samples are not. A recent study (Guoet al. 2014) presented an interesting experimental analysis for wellbore strengthening in sandstones. In thisstudy, particulate LCM was used to strengthen the wellbore by corrective and preventing approaches.Overall, the performance of the preventive approach yield to better performance, which in turn, �100%was reported as increase in formation breakdown pressure, compared to a control sample (CS) with verysimilar in-situ stress conditions. The authors of that work argue that sealing of the fracture occurredmainly near wellbore; however, characterization of the seal along the fracture was not conducted throughoptical microscopy and/or SEM analysis. The darker color close to the wellbore on their core post-tesingmay be mud filtrate that took place while pumping to create the initial fracture. The wellbore strength-ening mechanism that resulted from the experimental analysis was not critically compared with the tipresistance or stress caging to understand the basic differences.Other wellbore strengthening mechanismsinclude the elastic-plastic fracture model proposed by Aadnoy and Belayneh (2004). They experimentallyproved that the fracture resistance is sensitive to mud composition. They explained the pressure increaseconsidering that cake does not get broken when the fracture is opened, indeed, it deforms plastically bymaintaining a barrier. This mud cake deformation cannot take place in low-permeability formations andthis was the reason why they did not find a match between the analytical and laboratory experiments. Theuse of high mechanical strength materials instead of polymer-based materials was reccommended. Thefracture breakdown pressure was observed to be very sensitive to particles content as bridging materials.Additional work on wellbore strengthening was reported in literature with either limited experimental orfield application evidence. These are listed as:

● Internal filter-cake bridging and time-dependent wellbore strengthening (Abousoleiman et al.2007; Reid and Santos 2006; Santos et al. 2006): development of an impermeable filter cakeformed inside the fracture increases fracture resistance

● Wettability change of filter cake (Brege et al. 2010): changing filter cake wettability in presenceof non-aqueous fluid from oil-wet to water-wet can increase the fracture healing of the mud

● Thermal effects (Gil et al. 2006; Gonzalez et al. 2004): The near wellbore fracture pressure can beincreased by thermal treatments and this facilitates the occurrence of stress caging in someinstances.

Experimental AnalysisThis section describes the most relevant aspects concerning the OBM and additives (NPs and graphite),sandstone samples characterization, and cores preparation steps. Hydraulic fracturing tests are alsodescribed.

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OBM and Additives Characterization

OBM was selected as the drilling fluid in this work. This type of mud is often used when drilling shaledue to its inhibitive characteristics, low density values for applications in subpressured basins, goodrheological properties at high temperatures and lubrication characteristics in comparison with WBM. Thecomposition of the OBM used in this research is presented in Table 1.

In-house prepared NPs were used in this work. NPs were prepared in-situ, i.e., inside the drilling mud,at different concentrations. In-situ preparation was conducted since it yields a superior filtration lossreduction in contrast to ex-situ preparation (Zakaria, 2013). According to SEM imaging on filter cakesafter filtration experiments, NP1 exhibit an average size of 30 nm (Zakaria, 2013). In general, NP2 havea bigger mean particle size than NP1 that was quantified as 60 nm (Zakaria, 2013). Commercial gradeprecursors were used for the formation of the NPs. Laboratory grade precursors were also used to performsome tests during an early experimental stage and the results obtained were practically similar to those byusing commercial grade precursors. As this work is intended to be applicable in industry operations,commercial grade precursors were selected to perform the experiments due to its lower cost. Blendscontaining NPs were then mixed with glide graphite at two different concentrations. Graphite was addedto the blends due to its high performance as wellbore strengthening material (Nwaoji 2012; Mostafavi2011; Fuh et al. 1992; Morita et al. 1990). Graphite concentrations of 0.5 wt% and 2.0 wt% were selectedas basis concentrations from screening tests that concluded that graphite concentrations �2.0 wt% willresult in significant precipitation while mixing. Graphite size predominantly ranged from 75 to 212microns. The maximum concentrations limits of NPs were established based on the performance of theseadditives on OBM from filtration experiments (Contreras et al. 2014). A maximum NP1 concentration of2.5 wt% was set as further values did not impact the filtration volume. Maximum concentration for NP2was set at 2.5 wt% since higher concentrations resulted in precipitations of NPs and precursors. Thisprecipitation could negatively impact the drilling hydraulics in real operations. Table 2 shows the selectedblends for wellbore strengthening tests. This includes blends nomenclature based on NPs and graphiteconcentration (in wt%). In field units, the NPs concentration ranged between 0.04 and 0.2 ppg.

Due to the complexity of the hydraulic fracturing experiments and the associated expenditures, effortsfocused on reducing the number of tests as much as possible but at the same time getting conclusiveresults. Blends at a medium NPs concentration of 1.0 wt% were not tested since it was observed that these

Table 1—OBM composition (Contreras et al. 2014).

Table 2—Wellbore Strengthening test matrices and blends nomenclature.

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blends did not give any filtration peak in the work conducted by Contreras et al. (2014) and just followeda slight trend between the lower (0.5 wt%) and maximum (2.5 wt%) NPs concentrations. Based on thehypothesis that wellbore strengthening is related to filtration, these intermediate concentrations are notexpected to be representative. Table 3 shows the rheology parameters at 120°F for each blend includingthe CS.

In general, the rheology was not significantly affected by the addition of NPs due to the smallconcentrations as discussed by Contreras et al. (2014). Zakaria (2013) also reported a slight change inrheology parameters due to the addition of the same NPs type on OBM. Slight reduction on plasticviscosity (PV) by the addition of NP1 are due to the presence of the hydroxyl group (OH-) on the NPssurface that creates agglomeration and a higher mass of selective physisorption of organic clay suspensionon the NPs free surface (Srivasta 2010). The reduction on the yield point by addition of NP1 is believedto occur due to the anionic nature of OH- and their interaction (acting as a thinner) with the charged edgesof the suspended clays on the mud. This effect can be seen as an analogy of the work performed bydeflocculants (commonly anionic polymers) that neutralize positive charges on clay surfaces and preventflocculation. Addition of NP2 increased the PV of the blends. The viscosity increase by addition ofcalcium-based NPs has also been reported by Zakaria (2013). Manea (2012) reported increase in viscosityof the blends by addition of calcium carbonate microparticles. The NP2 bridging capability on invertemulsions is believed to be the reason for the plastic viscosity increase and rheological stability (Zakaria,2013).

Sandstone Samples CharacterizationRoubidoux sandstone samples used in these experiments were obtained from outcrops located in JeffersonCity (mid-Missouri, US). This sandstone is an Ordovician, medium grained, laminated to thinly beddedquartz sandstone. X-ray diffraction (XRD) analysis showed a composition of 94% of quartz and 6% ofkaolinite (Abu Bakar and Gertsch 2011). Three slabs of 12��12��9� were used. The porosity wasmeasured experimentally using mercury injection on cores of 1�x2� taken from each slab. Absolutepermeability was also measured using nitrogen injection. Tensile strength was measured by conductingBrazilian tests on 2��1� cores. This set of tests was carried out with the aim of determining similaritybetween the samples obtained from each rock slab in order to guarantee that the same (or very similar)media were used for the hydraulic fracturing results to be compared.

Cores Preparation StepsThe sample preparation included a long and exhaustive process that started by drilling of the cores outfrom sandstone slabs, drilling of the wellbore, setting of casings and steel caps, and finally grinding of thecores to obtain a smooth surface. Details of the cores preparation steps can be found elsewere (Contreras2014). Figure 5 highlights the core drilling, caps cementing and core vacuuming.

Hydraulic Fracturing TestsThe cores were tested into a hydraulic fracturing apparatus presented in Figure 6 that applies overburdenand confining pressure, and allows injection of fluid into the wellbore using syringe pumps. More than oneinjection cycle was carried out and all the injection parameters vs. time were tracked using a software.

Table 3—Blends rheology parameters (Contreras et al. 2014).

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Wellbore strengthening was obtained using NPs inOBM and trends as a function of NPs and graphiteconcentrations were identified. The hydraulic frac-turing tests involved eight blends containing in-situprepared calcium-based (NP2), iron-based (NP1)NPs and graphite. Overburden pressure of 400 psiand confining pressure of 100 psi were applied tothe cores. A fluid injection rate of 5 ml/min wasused. The CS with no presence of NPs and graphitewas tested initially as a reference point. Two addi-tional tests using graphite at 0.5 wt% (with no NPs)and graphite at 2.0 wt% (with no NPs) were con-ducted to serve as reference points for identificationthe real effect of NPs addition on blends.

ResultsSandstone Samples CharacterizationPorosity, permeability, and tensile strength valuesobtained are presented in Table 4. Note that thesimilarity obtained from the samples ensured that effect of NPs and graphite was compared betweensamples after the hydraulic fracturing tests.

Hydraulic Fracturing TestsThe pressure (P) vs. time (t) plots for the CS, NP2, and NP1 blends combined graphite are presented inFigure 7 and Figure 8 respectively. The maximum breakdown pressure (Pfb) for the CS was quantified as1766 psi. This value was the basis to calculate the % Pfb increase for the other blends. The second injectioncycle reached a maximum pressure of 858 psi after 10 min of fracture healing. Note the wellborestrengthening effect that yield to Pfb values higher than the CS (1766 psi). The maximum pressuresobtained from the second injection cycle for NP2 blends are even higher than the Pfb for CS. Thisdemonstrates the strengthening effect resulting from the blends even for the re-opening pressures.Re-opening pressures from NP1 blends were not that high compared to NP2 blends and the possiblereason for this behavior is addressed later. Note that the pressure build-up for the CS took more timecompared to NP2 and NP1 blends. NPs blends pressure build-up occurred faster due to the formation of

Figure 5—(a) Sandstone core drilling arrangement. (b) Steel caps cementing. (c) Sandstone core vacuuming and saturation arrangement.

Figure 6—Hydraulic fracturing apparatus.

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lower-permeability filter cakes by presence of NPs and graphite. In the previous study on filtration fromthese blends conducted by Contreras et al. (2014), NPs blends gave considerable less filtration on porousmedia compared to the CS. Blends containing just graphite at 0.5 wt% and 2.0 wt% gave pressureincreases of 34.4 % and 27.7% respectively compared to the CS. Overall, the performance of NP2 blendswas better than NP1 blends for wellbore strengthening. The analysis and explanation of this phenomenonis carried out later using filtration results from the same blends and core post-testing analysis.

Cores for CS, DF1, and DC1 blends after the hydraulic fracturing experiments are shown in Figure 9.A vertical fracture was observed. Some fluid is observed around the vertical fractures. These cores servedfor further analysis with the aim of inferring about the predominant wellbore strengthening mechanism.A detailed analysis of the P vs t plots for DC1 and DF1 blends is presented in Figures 10 and 11. Whenthe Pfb from CS is compared with (Pfb)DC1 (the maximum pressure obtained from DC1), a 62.7% increaseis obtained. Likewise, (Pfb)DF1 gave a 39.2% of increase compared to the CS. The LOP between the twocurves was also compared. 36% and 15% of increase was obtained by DC1 and DF1 blends respectively.This analysis concluded that an increase in the LOP is indeed possible in contrast to the findings publishedby van Oort and Razavi (2014). This means that the situation described in Figure 4a is feasible and wassupported experimentally by this research.

Table 4—Porosity, permeability and tensile strength of sandstone samples.

Figure 7—P vs. t plot for CS and NP2 blends (Note that the pressure build-up for the CS took more time due to higher mud filtration).

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These experimental results may indicate that theFPR was not the predominant wellbore strengthen-ing mechanism. It is interesting to note that theseLOP increases over the CS are supported by thewellbore weakening effect due to pore pressure in-crease at the wellbore (Wang et al. 2007; Detournayet al. 1986; Haimison 1968). Since the CS gave ahigher mud filtration towards the formation com-pared to DC1 and DF1 blends (Contreras et al.2014), a lower LOP was experienced in that case.This fact may shed the light on a combination ofmechanism that resulted in the total wellborestrengthening reported in this research.

The wellbore strengthening results for NP2 andNP1 are summarized in Figure 12. Plots of % Pfb

increase vs. NP2 and NP1 concentration at the twodifferent graphite levels are presented. The Pfb forthe CS was taken as reference. A rapid increase inPfb was observed until NP2 concentration of 0.5wt% was reached. At NP2 concentrations � 0.5wt% a slighter Pfb increase was obtained. The lowergraphite level gave a better wellbore strengtheningeffect and this correlates with the better perfor- Figure 9—Cores after hydraulic fracturing experiments for CS, DF1,

and DC1 blends.

Figure 8—P vs. t plot for CS and NP1 blends (Note that the pressure build-up for the CS took more time due to higher mud filtration).

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mance of these blends in filtration on porous media (Contreras et al. 2014).A maximum Pfb increase of 65.1% was obtained at NP2 concentration of 2.5 wt%. At this point the

graphite level becomes less significant. Note that any addition of NP2 will significantly help thestrengthening mechanism compared to the case of blends containing only graphite (i.e., NP2 concentra-

Figure 10—P vs. T plot for DC1 indicating the Pfb and LOP increase with respect to the CS.

Figure 11—P vs. T plot for DF1 indicating the Pfb and LOP increase with respect to the CS.

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tion�0 wt%). A concentration increase up to 0.5 wt% of NP1 helped the strengthening mechanism.Further concentration increase will negatively impact the performance.

A maximum Pfb increase of 39.2% was obtained. Graphite effect in NP1 blends is not significant. Thismay occur since at high NP1 concentration, significant agglomeration of NPs take place and graphite nolonger can contribute in forming an effective seal. In general, NP2 performance is superior compared toNP1 in combination with graphite.

A comparison between wellbore strengthening and filtration reduction data at HPHT published byContreras et al. (2014) was conducted for NP2 blends at each graphite level (0.5 wt% and 2.0 wt%). Figure13 illustrates the comparison. The left vertical axis corresponds to % of Pfb increase while the right onestands for % HPHT filtration reduction. Note the strong match in tendency obtained between the twoparameters. This plot demonstrates that the wellbore strengthening performance is proportional to the mudfiltration during the hydraulic fracturing experiments. While a common industry thought is that thesuccess of wellbore strengthening depends on tracking mud filtration, this research concluded this fact ina quantitative way. For example, NP2 concentrations �0.5 wt% at low graphite level, do not significantlychange in filtration reduction. Similarly, the wellbore strengthening performance is improved approxi-mately at the same degree exposing a very similar low slope. This corroborates the appropriate selectionof the maximum concentration limits. From the wellbore strengthening and filtration reductions trends it

Figure 12—% Pfb increase vs. (a) NP2 and (b) NP1 concentration.

Figure 13—% Pfb increase (left axis) compared to % HPHT filtrate reduction (right axis) for NP2 blends at two graphite levels (a) 0.5 wt% and (b)2.0 wt%.

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can concluded that the better filtration reduction yield to a more effective strengthening effect. This meansthat some filtration is required for wellbore strengthening to take place; however, excessive filtratetowards the formation is not reccommended. Higher filtration rates are associated with high-permeabilityfilter cakes that yield to weak seals.

Figure 14 compares % of Pfb and % HPHT filtration reduction for NP1 blends. This figure highlightsthe proportionality between the wellbore strengthening performance and filtration at the two differentgraphite levels. Initially, a proportionality is observed in both plots at NP1 concentrations �0.5 wt%.Likewise, both plots show an inverse relationship as function of NP1 concentrations �0.5 wt%. From thisfigure it is concluded that excessive mud filtration (given at high NP1 concentrations) impairs thewellbore strengthening as discussed earlier. Higher filtrations values are associated with thicker filtercakes that result from poor NPs interaction with the clays in the drilling fluid. Significant NPsagglomeration is experienced in these cases and a weak seal is created. This research led to the hypothesisthat dehydration of the particles contained in the blend may occur significantly fast due to the highfiltration towards the formation and this will impede the transportation of the particles to the fracture tipand the creation of a strong seal.

Results from Figures 13 and 14 are plotted as % Pfb increase vs. % HPHT filtrate reduction for eachNPs type as shown in Figure 15. Note that the trend lines were set at zero values since the experimentaltesting relies on a CS, and therefore at 0% of filtration reduction no strengthening is expected. The arrowsindicate the direction of NPs concentration increase. At graphite concentration of 0.5 wt%, the relationshipbetween % Pfb increase (Pfbi) and % HPHT filtrate reduction at 30 min (Fr30min) for NP2 is:

Eq. 4

Eq. 4 shows almost a perfect fit between strengthening concentration and filtration reduction at HPHT.At 2.0 wt% of graphite, the relationship between Pfbi and Fr30min for NP2 is:

Eq. 5

These two equations show that there is a linear relationship between wellbore strengthening and HPHTfiltration for NP2. At 2.0 wt% of graphite a higher slope is obtained meaning that the wellborestrengthening is more sensitive to filtration reduction at HPHT in comparison to 0.5 wt%. From thesetrends, just with percentage in filtration reduction, an estimate of wellbore strengthening can be predicted.However, note that this plot includes two dependent variables and a careful interpretation is recom-mended. For NP1 a linear relationship was not obtained. This occurred since both parameters Pfbi and

Figure 14—% Pfb increase (left axis) compared to % HPHT filtrate reduction (right axis) for NP1 blends at two graphite levels (a) 0.5 wt% and (b)2.0 wt%.

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Fr30min decrease at NP1 concentrations �0.5 wt%. However, proportionality as a function of NP1concentration in the trends is visualized. At NP1 concentrations �0.5 wt% there is a direct proportionality.At NP1 concentrations �0.5wt% there is an inverse proportionality.

Results DiscussionWellbore strengthening was successfully achieved by in-situ prepared NPs on the sandstone cores used inthis research. An initial LOP increase was believed to occur due to an effective filter cake formed aroundthe wellbore preventing pore pressure increase. A strong match between wellbore strengthening andfiltration at HPHT was found and this could lead to inferences about the physical phenomenon of thestrengthening process. Overall, for a particular NP type, higher filtration was proportionally associatedwith a less significant wellbore strengthening. The hypothesis behind this finding that this paper proposesrelies on the fact that while it is true that some filtration is required for the carrier fluid to dehydrate andform an immobile mass into the formation, excessive mud filtration produces NPs agglomeration andrapid dehydration of the blend while traveling along the fracture. If this occurs, the particles will not havean effective transport medium to travel and deposit at the fracture tip.

NP1 blends gave in average less filtration than NP2. However, NP2 blends performed better in thestrengthening experiments. A relationship between these two different phenomena needs to be conductedcarefully and the differences required to be fully understood. First, NP1 and NP2 are different in nature.NP1 are smaller than NP2 and NP2 have a bigger particle size distribution that could at first glance helpfor the strengthening process as some authors argue (van Oort et al. 2011; Aston et al. 2004; Alberty andMcLean 2004). Secondly, while the filtration occurred at constant pressure of 500 psi in a static process,the wellbore strengthening is a dynamic process that occurred at pressures �2000 psi. Finally, NP1 blendshave in average less viscosity than NP2 blends. From this research results, the next hypothesis is proposedto explain this contrast between filtration and wellbore strengthening for NP1 and NP2. Since NP1 blendsare less viscous and give less filtration, the carrier fluid containing NPs and graphite will travel fastthrough the fracture plane generating small blend dehydration. This will result in a weak seal comparedto the seal that is created by NP2 blends. This claim can be supported by P vs. t plots obtained from thehydraulic fracturing experiments. Note that in the P vs. t plots for NP1 blends (Figure 8) that the duringthe first injection cycle, some pressure peaks were obtained. However, the maximum pressure reachedcorresponded to the first of those peaks. It can be inferred that once the first seal was broken, the blendinside the fracture was unable to create a stronger seal. On the other hand, from the P vs. t plots for NP2blends (Figure 7), the the first pressure peak did not correspond to the maximum pressure recorded. Thismeans that once the first seal was broken, the blend inside the fracture was able to create a stronger one.

Figure 15—% Pfb increase vs. % HPHT filtrate reduction for (a) NP2 and (b) NP1. Arrows indicate the direction of NPs concentration increase.

SPE-170263-MS 15

This could have occurred since the NP2 blend traveled slower along the fracture due to their higherviscosity and the carrier fluid dehydration properly took place resulting in stronger seals that led to higherPfb.

Core Post-Testing AnalysesCore post-testing analyses were conducted to infer about the predominant wellbore strengtheningmechanism. Optical microscopy, SEM, and EDX analyses supported the study performed in this paper.While industry cannot unanimously conclude on a predominant wellbore strengthening mechanism, thisresearch presented evidence to explain the phenomenon. Figure 16 shows a top view of a sandstone corewith vertical fractures from the wellbore. The same fracture width is observed from the wellbore to thecore end. According to the stress caging theory, solids are deposited in the fracture mouth forming animpermeable bridge. This bridge keeps the fracture open and increases the hoop stress once the fracturestarts closing when pressure into the fracture dissipates. However, from this figure a bridge at the fracturemouth with a bigger width is not observed. In fact, the fracture width at the wellbore is even narrower thanother fracture sections. Figure 16 also shows a cross-section taken from the fracture plane. From thiscross-section, graphite was observed all the way along the fracture plane. White zones along the fractureplane are believed to be agglomerations of NP2.

The average fracture width was quantified using an optical digital microscope. Figure 17 shows animage of the fracture at the wellbore. An average fracture width of 0.2 mm was observed from wellboreto core end. Note the color difference between the filter cake (dark area) around the wellbore and the bulkof the sample. A 3D representation of the vertical fracture at the wellbore was conducted.

Figure 16—Top view and cross-section of the sandstone core post-testing. Note that graphite was observed along the complete fracture plane.

Figure 17—Fracture at the wellbore (left) and 3D representation of the wellbore containing the fracture (right).

16 SPE-170263-MS

Figure 18 shows an optical microscope image at core end and a 3D image of the core end. Graphitecan be observed as black particles. 3D image of the fracture at the core end was also performed. SEM andEDX analysis were performed on different sections of a sandstone core where NP2 were used. ASchottky-type emitter was used as the electron source. Imaging along the fracture was conducted from thefracture mouth, middle fracture, and at the fracture end. The samples were obtained from these locationsas illustrated in Figure 19.

Figure 20 shows SEM and EDX results from fracture top view at three different locations: fracturemouth, middle fracture, and fracture end. A fracture seal was observed at the three locations exhibitingan average thickness of 40 �m. This goes against the stress caging theory considerations. EDX allowedthe identification of the calcium prone regions as a result of NP2 presence on the seal shown as pink color.

A nano-scale image in Figure 21 shows NP2 of size �150 nm. A much higher resolution image didnot allow an easy visualization due to operational limitations. NP2 were observed to form agglomarationsthat can be vizualized in rounded shapes or as ovals. NP2 are believed to have an average size even lowerthan 100 nm since CaCO3 crystals were not observed from these SEM images.

The occurrence of the chemical reaction that produces NP2 and NaCl was demonstrated by a mappingof the chemical compounds Ca, Na, and Cl on the fracture seal, the fracture plane and the filter cakearound the wellbore. Figure 22 illustrates the chemical compounds characterization in contrast to the SEMimages at three different locations.

Figure 18—Fracture at core end (left) and 3D representation of the core end containing the fracture (right).

Figure 19—Location and nomenclature of sandstone samples analyzed.

SPE-170263-MS 17

Figure 20—SEM and EDX of fracture seal along a fracture plane cross-section indicating the presence of calcium particles (as pink regions).

Figure 21—(a) NP2 at seal cross-section. (b) NP2 at fracture plane. Particles highlighted with red arrows have size <150nm.

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Figure 23—Wellbore filter cake cross-section (left) and front view (right).

Figure 22—EDX of Ca, Na, and Cl. Light blue color represents NaCl as a result of green (Na) and blue (Cl) colors mixing.

SPE-170263-MS 19

The light blue color represents the NaCl as a result of mixing of green (Na) and blue (Cl) colors. Thepink color indicates the calcium prone regions with the presence of calcium carbonate. There is ahomogeneos distribution of NP2 in the front view of fracture plane. This analisys explicitly proves theoccurrence of the chemical reaction by the in-situ procedure developed in this research. The filter cake atthe wellbore was characterized to determine the thickness and texture. Figure 23 shows a cross-section ofthe wellbore that allows the quantification of the filter cake in 300 �m. This is a desirable thickness infield operations to avoid stuck pipe and any other implication of thick cakes especially when drillingdeviated wellbores. A front view of the filter cake shows few cracks that resulted from cake dehydtrationafter exposure to air. This figure also shows the strong adherence between filter cake and the rock itself.Gaps between them are not observed. This is an important observation in spite of the cake dehydration.

ConclusionsThis research was the result of multidisciplinary efforts on the study of wellbore strengthening. The in-situprepared NPs virtues as a wellbore strengthening agent were investigated. Results demonstrated thatwellbore strengthening is possible in sandstone cores using the in-house prepared NPs at low concentra-tion in OBM. The predominant wellbore strengthening mechanism was identified through opticalmicroscopy, SEM, and EDX analyses of cores post-testing. A strong match between wellbore strength-ening and mud filtration at HPHT in permeable media was found and this allowed a better understandingof the phenomena behind wellbore strengthening. The wellbore strengthening trends as a function ofblends concentration were established. Overall, NP2 were superior to NP1 as wellbore strengtheningadditives. Wellbore strengthening reached a maximum value of 65% using NP2 and graphite. A maximumfracture pressure increase of 39.2% was recorded using NP1 and graphite. This different performance wasexplained based on different filtration reductions obtained from the two NPs types and viscosity of theblends. Tip resistance by the development of an immobile mass was identified as the predominantwellbore strengthening mechanism by ruling out the occurrence of other possible mechanisms andpost-testing analysis. Some filtration was observed to be beneficial but high filtration impairs the wellborestrengthening mechanism. This was explained based on the hypothesis that the high-filtration blends thattraveled along the fracture became quickly dehydrated and particles did not completely reach the fracturetip. The chemical reaction for the formation of NP2 was corroborated by conducting EDX analysis. A thinseal composed of NP2 in a sandstone core developed along the fracture and wellbore with a homogenousNPs distribution.

AcknowledgementsThe authors would like to thank Talisman Energy, Pason Systems Corporation, the Natural Sciences andEngineering Research Council of Canada (NSERC) for supporting this research. Special thanks to AzraTutuncu and Michael Basset for their technical advice in the experimental stage of this work.

Acronyms

CS : Control sampleDCi (i�1, 3, 4, 6) : Blends containing calcium-based nanoparticles at different concentrationsDFi (i�1, 3, 4, 6) : Blends containing iron-based nanoparticles at different concentrationsEDX : Energy dispersive X-ray spectroscopyFIP : Fracture initiation pressureFPR : Fracture propagation resistanceHPHT : High-pressure high-temperatureLCM : Lost circulation material(s)LOP : Leak-off point

20 SPE-170263-MS

LOT : Leak-off testNPs : NanoparticlesNP1 : Iron-based nanoparticlesNP2 : Calcium-based nanoparticlesNSERC : Natural Sciences and Engineering Research Council of CanadaOBM : Oil based mudPV : Plastic viscositySEM : Scanning electron microscopeWBM : Water based mud

Nomenclature

Fr30min : High-pressure high-temperature filtrate reduction at 30 min (%)P : Pressure (psi)Pfb : Maximum breakdown pressure (psi)Pfbi : Pressure breakdown pressure increase (%)Pfi(i�1,2,3) : Pressure of the fluid into the fracture (psi)Poi(i�1,2, 3): Pore pressure (psi)Pwi(i�1,2,3) : Wellbore pressure (psi)R2 : Coefficient of determination (dimensionless)�h’ : Effective in-situ horizontal stress (psi)t : Time (min)

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