researcharticle chemical effect on wellbore instability of

Hindawi Publishing CorporationThe Scientific World JournalVolume 2013 Article ID 931034 7 pageshttpdxdoiorg1011552013931034

Research ArticleChemical Effect on Wellbore Instability of Nahr Umr Shale

Baohua Yu1 Chuanliang Yan1 and Zhen Nie2

1 State Key Laboratory of Petroleum Resource and Prospecting China University of Petroleum Beijing 102249 China2 Exploration amp Production Research Institute CNPC Beijing 100011 China

Correspondence should be addressed to Chuanliang Yan yanchuanliang163com

Received 15 July 2013 Accepted 8 September 2013

Academic Editors A M Efstathiou and A Vorontsov

Copyright copy 2013 Baohua Yu et al This is an open access article distributed under the Creative Commons Attribution Licensewhich permits unrestricted use distribution and reproduction in any medium provided the original work is properly cited

Wellbore instability is one of the major problems that hamper the drilling speed in Halfaya Oilfield Comprehensive analysis ofgeological and engineering data indicates that Halfaya Oilfield features fractured shale in the Nahr Umr Formation Complexaccidents such as wellbore collapse and sticking emerged frequently in this formation Tests and theoretical analysis revealed thatwellbore instability in the Halfaya Oilfield was influenced by chemical effect of fractured shale and the formation water with highionic concentrationThe influence of three types of drilling fluids on the rockmechanical properties ofNahrUmr Shale is tested andtime-dependent collapse pressure is calculated Finally we put forward engineering countermeasures for safety drilling in HalfayaOilfield and point out that increasing the ionic concentration and improving the sealing capacity of the drilling fluid are the way tokeep the wellbore stable

1 Introduction

The Nahr Umr Shale Formation is found throughout thesouthern part of the Arabian Gulf and forms the cap rockto many major reservoirs in the region [1] Major wellboreinstability problems when drilling through this shale for-mation have often arisen not only in new wells but alsoin reentry wells especially with the rise of water-basedmud and stricter environmental control making wellborestability in this shale an extremely challenging operation fordrillingmud engineers

The Halfaya Oilfield is in the south of Missan provincein Iraq which is 400 km south east of Baghdad the capitalof Iraq Three horizontal wells in the Nahr Umr Formationof Halfaya Oilfield had been drilled But two wells of thethree horizontal wells have sidetracking due to sticking onlyone horizontal well is drilled successfully so it illustrates thebig effects of wellbore instability problems on the directionaldrilling in this oilfield

2 Geological Character

The Halfaya Oilfield is located on the Arabian shelf whichis adjacent to the Zagros tectonic zone The influence of

Zagros tectonic movement is the extrusion to the Arabianshelf by the European plate (NNE-SSW) The propagation ofthe stress wave leads to a series of anticlines in the Arab shellThis extrusion stopped in Middle Miocene The geologicalstructure is a low dip anticline in which the long axis is nearlyperpendicular to the Zagros extrusion stress field [2ndash4] Thestructure is above the Arabian shelf and is far away from theZagros fault control zone but the structure is still affectedby Zagros tectonic movement which makes the in situ stresscomplicated

There is no large fault which could be recognized byseismic data The anticline structure is also very smooth Theresults show that the extrusion stress by the Zagros tectonicmovement is not very strong and the extrusion stress doesnot produce strong in situ deformation and destruction

The lithologic characters in the Halfaya Oilfield fromthe top to the bottom is respectively the Tertiary UpperFars Group mainly sandy mudstone about 1300m thick theLower Fars Group mainly anhydrite salt rock and shaledeposit about 500m thick being the regional cap rockthe Tertiary Kirkuk Group which is mainly sandstone andmudstone about 300m from the Tertiary Jaddala group tothe Nahr Umr group mainly carbonatite and interlayers ofthin marl sandstone and shale

2 The Scientific World Journal

3 Drilling Problems

Three horizontal wells N001H N006H and N002H in theNahr Umr Formation of Halfaya Oilfield had been drilledThe well distributions are both located in the structural longaxis direction The complicated drilling problems of thesethree wells are as follows

When the first horizontal well (N001STwell) encounteredthe Nahr Umr layer there were two sidetracking operationsThe first sidetracking happened at 394126m the SLB screwstuck in the highly deviated interval and the directionaltool dropped in the well The fishing failed which led tosidetrackingThe second sidetracking happened at 409121mthe Nahr Umr Shale collapsed and this led to stickingat 4087m the treatment measures was ineffective and asidetracking operation happened

The second horizontal well (N006ST well) used theorganic salt drilling fluid which has a strong inhibitionWhen drilling 3964m the Nahr Umr Shale collapsed andthe treatment measure for the sticking failed so sidetrackinghappened at 3800m using the vertical well completion

The third horizontal well N002Hused saturated salt waterdrilling but there were many sticks between 3660m and3895m in the Nahr Umr Formation and there were cavingsat the shaking screen

The twowells of the three horizontal wells have sidetrack-ing due to sticking only one horizontal well was drilled suc-cessfully so it illustrates the big effects of wellbore instabilityproblems in the oilfield The wellbore instability has seriousimpact for oilfield drilling and it restricts the explorationand development in the oil field As the development wellsare generally directional wells or horizontal wells and thewellbore instability risk is great wellbore stability analysis isneeded in the Halfaya Oilfield

4 Wellbore Instability Mechanism

41 Character of the Instable Shale Figure 1 shows the loggingdata of the Nahr Umr Formation of N004 well The GRlogging shows that the formations are mainly sandstone andshale The caliper logging shows that there are both stableand instable intervals Compared to the GR logging data thelithology of collapsing interval is shale and the sandstoneinterval is stable According to the interval transit timelogging data the interval transit time of the Nahr Umr Shaleis obviously higher than the adjacent sandstone intervalThe density logging data of the shale are obviously lowerthan the adjacent sandstone interval The reasons for thisphenomenon are the rich internal microfractures drillingfluid and the filtrate seepageThis can be seen from the photoof the Nahr Umr Shale (Figure 2) In addition the shape ofcavings of the Nahr Umr Shale indicates that the shale isenriched in fractures (Figure 3)

The main reason for wellbore instability in hard brittleshale with lots of fractures is as follows [5ndash11] If the sealingcapacity of the drilling fluid is not enough or the ionicconcentration is not enough to balance the formation waterionic concentration the drilling fluid and the filtrate wouldflow into the microfractures under the driving power from

the fluid column pressure difference of drilling fluid and theionic concentration difference This would lead the frictioncoefficients of the fracture plane to decrease the effectivestresses around the wellbore to decrease the formationaround the wellbore to become loose and the support ofthe drilling fluid column to the wellbore wall decrease Thusthe formation fluid will flow into the wellbore During thereaming and back reaming the disturbance of the rigs to theloose formation will lead to wellbore instability

42 Wellbore Instability Analysis In order to solve the well-bore instability of the fractured and hard-brittle shale inNahrUmr Formation the drilling fluid property and engineeringcountermeasures should be taken into account We analyzethe wellbore instability reasons combined with the drillingengineering measures of three horizontal wells in the NahrUmr Formation

When using rational engineering measures the drillingfluid property decides the wellbore stability during drillingto a large extent Table 1 shows the drilling fluid propertyused in these three horizontal wells These three wells usedthree different types of drilling fluid The following can beconcluded from the drilling fluid property parameters in thetable

(1) Based on the mud rheological parameters for theformation with good completeness the rheological param-eters of these three wells are similar and could meet theengineering requirement But for the fractured shale for-mation the rheological parameters of these three wells aredifferent Compared to the other two wells the drilling fluidof N001H well has a low viscosity which is bad for carryingthe cuttings and cavings In addition the drilling fluid withlow viscosity will easily flow into the formation under thepressure difference Therefore the rheological parameters ofdrilling fluid of N002Hwell benefit wellbore stability Usuallyincreasing the drilling fluid viscosity is of benefit for fractureformation

(2) Based on the drilling fluid filter loss the filter lossesof these three wells are similar Because the filter loss ismeasured by the experimental instrument in the laboratorythe results cannot reflect the real formation situation and it isonly a reference index

(3) Based on the drilling fluid ionic concentrationalthough there are not ionic concentration parameters ofN001H well drilling fluid in the daily drilling report accord-ing to the drilling fluid description provided by the drillingfluid service provider the drilling fluid ionic concentrationsof this well could indicate that the ionic concentration of KCLPolymer drilling fluid used in the N001H well is betweenthe concentrations of the N002H well and N006H well theionic concentration of the N002Hwell is the highest the ionicconcentration of the N006Hwell is the lowestWhen the holeis opened the ionic concentration difference of the drillingfluid and formation water is the main driving force thatdrives the free water in the drilling fluid into the formationCommonly the high ionic concentration of drilling fluid isof benefit to prevent the free water in the drilling fluid fromflowing into the formation If the free water in the drillingfluid flows into the formation the formationwill be hydrated

The Scientific World Journal 3

19 21 23 25 27 29 31100 150 200AC (usft)

8 10 12 14 16CAL (in)

3640

3645

3650

3655

3660

3665

3670

3675

3680

3685

3690

3695

3700

0 30 60 90 120 150GR (API)

Dep

th (m

)

Density (gcm3)

Figure 1The comparison of the logging data in Nahr Umr Formation GR natural gamma logging CAL caliper logging AC acoustic transittime logging

Figure 2 The core of Nahr Umr Shale

and the formation strength will be decreased so as to leadto wellbore periodic collapsing Table 2 shows the formationwater property of Halfaya Oilfield The results show that theformation water has an extremely high ionic concentrationwhich needs a high ionic concentration for drilling fluid tobalance it

43 Shale Hydration According to the formation characterthe Nahr Umr Shale is abundant in microfractures theformation is broken and the drilling fluid can easily flowinto the micro fracture plane which leads to the change offormation strength In order to prevent wellbore instabilitythe drilling fluid property should be improvedThe influence

Figure 3 The shale cavings of the Nahr Umr Shale of N006HWell

of drilling fluid on the wellbore stability is analyzed from themineral composition the drilling fluid consistency and theinfluence of the drilling fluid on formation strength

Tables 3 and 4 illustrate the minerals and clay mineralscomposition and content of theNahrUmr Shale respectivelyThe test results in the tables show that the Nahr Umr Shalemainly consists of quartz and clay especially quartz whichexceeds 485 For shale Formation the higher the quartzthe higher the brittleness at the same time the content of theclay minerals of the shale belongs to medium and little highlevel The clay minerals mainly consist of illitesmectite andkaolinite and the content of smectite is low The type of theclaymineral indicates that the shale is very brittle In additionthe kaolinite is a stable clay mineral and the hydration of


Table 1 The drilling fluid properties of three horizontal wells of Nahr Umr Formation

Well noN001H well-Hole 1 N001H well-Hole 2 N002H well N006H well

Mud type KCL-polymer KCL-polymer Salt saturated BH-WEIDensity (gcm3) 125 125 128 128Viscosity (s) 51 53 78 65Plastic viscosity (cp) 26 27 41 39YP (lb100 ft2) 24 26 31 29Gel strength 1010158401015840101015840 (lb100 ft2) 58 514 79 57API filtrate (mL) 32 34 30 3Mud cake (mm) 03 03 03 05PH 95 9 9 85Solid () 13 11 13 17Sand () 03 03 02 03Bentonite content (gL) 27 26 38Potassium (mgL) 27000Chloride (mgL) 55000 11520Ca+ (mgL) 200

Table 2 The formation fluid properties of Halfaya oilfield

Unit Nahr UmrWater type CaCl2PH 63Specific gravity (1556∘C) sg 1121Resistivity (25∘C) ohmsdotm 0068Total salinity ppm 166661Total hardness mgL 16562Na+ mgL 60015Ca2+ mgL 8681Mg2+ mgL 993Fe2+ mgL 74Ba2+ mgL 1K+ mgL 716Sr2+ mgL 356Clminus mgL 107098SO4

2minus mgL 874HCO

3

minus mgL 7263CO3

2minus mgL 0OHminus mgL 0

the illitesmectite is also feeble The type and content of theclay minerals both indicate that Nahr Umr Shale Formationis a hard and brittle formation which is hard to hydrate

According to research experience if the drilling fluidinhibition is good enough a formation like the Nahr UmrShale is impossible to hydrate without expansion collapsingTherefore we evaluate the rejection capacity of three drillingfluid systemswhich are used in theHalfayaOilfieldThe threedrilling fluids are organic salt drilling fluid Gel-polymerdrilling fluid and KCl-polymer drilling fluid

The densities of these three types of drilling fluid are all133 gcm3 then we measured the cuttings recovery (The 40 gcuttings with 32sim20mm diameter injected to the 350mLfluid Roll 16 h in a set temperature Then filter the cuttingsthrough a sieve Dry and weigh cuttings to calculate thecuttings recovery) and swelling ratio of these three drillingfluids The results are shown in Table 5 The results show thatthe cuttings recoveries of these three types of drilling fluidare both higher than 95 for the Nahr Umr Shale althoughthe swelling ratios are different These results show that theinhibitive capacity of the drilling fluid is good [12] on theother hand the results indicate that the formation hydrationis feeble The inhibitive capacity of the drilling fluid is notthe main reason for the wellbore instability of the Nahr UmrShale

In order to analyze the influence of the drilling fluid onthe wellbore stability of the Nahr Umr Shale experimentalstudies were carried on the influence of drilling fluid onthe rock mechanical property We tested the shale strengthof Nahr Umr Shale after immersing it in different kindsof drilling fluids Table 6 shows the uniaxial compressivestrength (UCSMPa) results from the test Figure 4 illustratesthe comparison of the strength variation rule versus the timeafter immersing in different kinds of drilling fluid

Figure 4 shows that the shale UCS decreases greatly afterimmersing it in the organic salt drilling fluid the next is theKCL-polymer drilling fluid the strength in the Gel-polymerdrilling fluid changed a little Therefore the Gel-polymerdrilling fluid benefits the wellbore stability of the Nahr UmrShale

Under the drive force of the ionic concentration differ-ence the free water in the drilling fluid which flows intothe formation would decrease the rock strength which isthe main reason for the collapse in Nahr Umr Shale inaddition as the formation is extremely hard and brittleand the fractures are rich internally if the drilling fluid


Table 3 Mineral composition and content of the Nahr Umr Shale

Depth Mineral content ()Quartz Potassium feldspar Soda feldspar Anorthose Calcite Dolomite Iron pyrite Hematite TCCM

364510 517 08 02 27 446364983 608 12 04 47 329366600 485 19 03 14 45 434

Table 4 Clay mineral composition and content of the Nahr UmrShale

Depth Clay mineral content () Interbed ratio ( S)S IS It Kao C CS IS CS

364510 34 7 48 11 14364983 33 3 40 24 11366600 44 7 49 21

Table 5 Swelling ratio and recovery of the Nahr Umr Shale

Organic salt KCL-polymer Gel-polymerRecovery Rate () 95 96 97Swelling Ratio () 24 36 22

Table 6 Experimental results of shale UCS after immersing indrilling fluid

Drilling fluid type Organic salt KCL-polymer Gel-polymerUCS without immersing(MPa) 4862 5109 4722

UCS with immersing of24 h (MPa) 4016 448 448




sealing capacity is not good enough the drilling fluid andfiltrate would flow into the rock along the microfractureunder the difference of the drilling fluid column pressureand pore pressure so as to weaken the formation strengthand lead to wellbore collapse So the increasing of the ionicconcentration of the drilling fluid and enhancing the drillingfluid sealing capacity is the key to the wellbore stability of theNahr Umr Shale

5 Time-Dependent Collapse Pressure

According to mechanical concepts the main reason forborehole collapse is caused by shear failure for the reasonthat stresses loaded on rock around the borehole exceed therock strength as a result of lower mud column pressureNow brittle formation collapsewill generate and the boreholewill enlarge for plastic formation plastic deformation be willgenerated and borehole shrinkage will be encountered

05055

06065

07075

08085

09095

1

0 20 40 60 80 100Immersed time (h)

Stre

ngth

ratio

(im

mer

sed

not i

mm

erse

d)

Organic saltKCL-polymerGel-polymer

Figure 4 Comparison of the shale strength decrease after immers-ing

Generally borehole collapse takes place in the minimumhorizontal stress direction 120579 = 1205872 or 31205872 [12] the boreholestress on minimum horizontal stress direction [13ndash20] is asfollows

120590

119903= 119875 minus 120575120601 (119875 minus 119875

119901)

120590

120579= 3120590

119867minus 120590

ℎminus 119875 + 120575 [

120572 (1 minus 2])1 minus ]

minus 120601] (119875 minus 119875

119901)

120590

119911= 120590V + 2] (120590119867 minus 120590ℎ) + 120575 [

120572 (1 minus 2])1 minus ]

minus 120601] (119875 minus 119875

119901)

(1)

Assume that safe coefficient FS [21] is as follows

FS =120590

119899119905119892120593 + 119862

120591

(2)

And let

119872 = 1 + (FS minus 1) cos2120593 (3)

Replace normal stress 120590119899as principal stress 120590

1and 120590

3

120590

119899=

120590

1+ 120590

3

2

minus

120590

1minus 120590

3

2

sin120593 minus 120572119875119901 (4)

Rewrite Mohr-Coulomb criterion [21]

119872(120590

1minus 120590

3) minus sin120593 (120590

1+ 120590

3minus 2120572119875

119901) minus 2119862 cos120593 = 0

(5)



1

11

12

13

14

15

16

0 20 40 60 80 100Immersed time (h)

Col

lapse

pre

ssur

e (g

cm3)

Figure 5 Time-dependent collapse pressure of Nahr Umr Shale

Based on different borehole stress conditions boreholecollapsing pressure expresses as a different form When thebearing condition is 120590

120579gt 120590

119911gt 120590

119903 maximum and minimum

stress separately are 1205901= 120590

120579 1205903= 120590

119903 and make 119896 = (120572(1 minus

2])(1 minus ])) minus 120601 under mud penetrating borehole face theborehole collapsing pressure model is

119875

119888119903= (2119862 cos120601 + (sin120601 minus119872) (3120590

119867minus 120590

ℎ)

+ [120575119872119896 + sin120601 (2120575119891 minus 120575119896 minus 2119896)] 119875119901)

times (120575119896 sin120601 minus119872(2 + 120575119896 minus 2120575119891))minus1

(6)

For the hard-brittle shale of Nahr Umr Formationaccording to the study results and experimental results theinfluence of the drilling fluid immersion on the mechanicalproperty mainly reflects in the decrease of the compressivestrength as the immersing time increase

Figure 5 illustrates the variation of collapse pressure ver-sus the hole opening time for Nahr Umr Shale The collapsepressure would increase as the formation strength decreasesthe increasing speed decreases gradually The increasing rateof Gel-polymer drilling fluid is the lowest in a certain drillingfluid density it can keep the wellbore stability for the longesttime The increasing of the mud density could only keepthe wellbore stability in limited time If the property of thedrilling fluid cannot be improved increasing themud densitywould force the drilling fluid to flow into the formation andmake the wellbore unstable

6 Countermeasures Dealing withWellbore Instability

In order to prevent the wellbore instability of Nahr UmrShale we come up with the following drilling technologycountermeasures and suggestions

(i) Depending only on the drilling fluid density cannotsolve the wellbore stability of the shale formation

which is full of fractures [22 23] If the drilling densityis too high the pore pressure would increase and theeffective stresses around the wellbore decrease andthis would cause a larger damaged scale Decreasingthe drilling fluid filter loss and improving the drillingfluid rheological property would benefit wellborestability

(ii) Commonly the larger the inclination the more pos-sible the wellbore instability But for the laminar frac-ture formation decreasing the angle of the wellboreaxial line with the bedding normal direction is ofbenefit for the wellbore stability

(iii) The influences of the swabbing pressure and surgepressure should be taken into consideration whenevaluating wellbore stability the simplified bottomhole assembly (BHA) could prevent large swabbingpressure and surge pressure and then prevent sticking

(iv) The hydraulic jetting is not suitable because the highpressure hydraulic jettingwould producewaterwedgeeffect in the progress of the drilling seepage The bigdiameter jet or no-jet are welcomed

(v) Avoiding the intense change of the dogleg or the welltrack so as to prevent big drill string acting force tothe wellbore wall

(vi) Optimizing the hydraulic parameters so as to ensurethe cuttings could be carried out of the wellboretimely For some situations wellbore collapse cannot be prevented so carrying out the cuttings in atimely way could decrease the downhole complicatedtime Increasing the drilling rate could decrease theexposed time of the shale formation which is usefulfor the wellbore stability

(vii) The formation water has an extremely high ionicconcentration so keep a high ionic concentration forthe drilling fluid to balance it

7 Conclusions

Under the function of the ionic concentration differencethe free water in the drilling fluid which flows into theformation will decrease the rock compressive strength whichis the main reason for the collapse in Nahr Umr Shale inaddition as the formation is extremely hard and brittle andthe fractures are internally rich if the drilling fluid sealingcapacity is not good enough the drilling fluid and filtratewill flow into the rock along the micro fracture surface underthe difference of the drilling fluid column pressure and porepressure so as to weaken the formation strength and lead towellbore collapse So increasing the ionic concentration ofthe drilling fluid to enhance the drilling fluid sealing capacityis the key point to thewellbore stability of theNahrUmr ShaleFormation

The collapse pressure will increase as the forma-tion strength decreases after drilling the increasing speeddecreases gradually The increasing rate of Gel-polymerdrilling fluid is the lowest in a certain drilling fluid density itcan keep the wellbore stable for the longest timeThe increase


of the mud density could only keep the wellbore stability fora limited time Improving the property of the drilling fluid isthe basis for keeping the wellbore stable

Acknowledgments

This work is financially supported by the Science Fund forCreative Research Groups of the National Natural ScienceFoundation of China (Grant no 51221003) and National Oiland Gas Major Project of China (Grant no 2011ZX05009-005)

References

[1] V X Nguyen Y N Abousleiman and S K Hoang ldquoAnalysesof wellbore instability in drilling through chemically activefractured-rock formationsrdquo SPE Journal vol 14 no 2 pp 283ndash301 2009

[2] Z Nie H Liu A Liu et al ldquoThe large temperature differencelong column and narrow clearance cementing best practices inHalfaya oilfieldrdquo in SPE Asia Pacific Oil and Gas Conference andExhibition October 2012

[3] M Zhang Z Tian S Xu et al ldquoResearch and application of BH-ATH (anti-three high) drilling fluid systemrdquo in IADCSPE AsiaPacific Drilling Technology Conference and Exhibition July 2012

[4] H Rabia Iraqi Oil Reserves Opportunities for Production andExploration 2008

[5] B S Aadnoy ldquoIntroduction to special issue on borehole stabil-ityrdquo Journal of Petroleum Science and Engineering vol 38 no3-4 pp 79ndash82 2003

[6] B S Aadony ldquoModeling of the stability of highly inclined bore-holes in anisotropic rock formationsrdquo SPE Drilling Engineeringvol 3 no 3 pp 259ndash268 1987

[7] F J Santarelli C Dardeau and C Zurdo ldquoDrilling throughhinghly fractured formations a problem a medel and a curerdquoin Proceedings of the SPE Annual Technical Conference andExhibition October 1992

[8] O A Helstrup Z Chen and S S Rahman ldquoTime-dependentwellbore instability and ballooning in naturally fractured for-mationsrdquo Journal of Petroleum Science and Engineering vol 43no 1-2 pp 113ndash128 2004

[9] R Narayanasamy D Barr and A Milne ldquoWellbore instabilitypredictions within the cretaceous mudstones clair field Westof Shetlandsrdquo in Offshore Europe Paper SPE 124464 AberdeenUK 2009

[10] B H Yu Study on Borehole Unstable Mechanism of LayeredShale China University of Petroleum Beijing China 2006

[11] J L Yuan J G Deng Q Tan B H Yu and X C Jin ldquoBoreholestability analysis of horizontal drilling in shale gas reservoirsrdquoRock Mechanics and Rock Engineering vol 46 no 5 pp 1157ndash1164 2013

[12] J N YanDrilling Fluid Technology ChinaUniversity of Petrole-um Press 2001

[13] E Fjaeligr R M Holt P Horsrud et al Petroleum Related RockMechanics Elsevier 2nd edition 2008

[14] J S Bell and D I Gough ldquoNortheast-Southwest compressivestress in Alberta evidence from oil wellsrdquo Earth and PlanetaryScience Letters vol 45 no 2 pp 475ndash482 1979

[15] D I Gough and J S Bell ldquoStress orientations from boreholewall fractures with examples from Colorado East Texas and

Northern Canadardquo Canadian Journal of Earth Sciences vol 19no 7 pp 1358ndash1370 1982

[16] M D Zoback D Moos L Mastin and R N AndersonldquoWell bore breakouts and in situ stressrdquo Journal of GeophysicalResearch vol 90 no 7 pp 5523ndash5530 1985

[17] S H Hickman J H Healy and M D Zoback ldquoIn situstress natural fracture distribution and borehole elongation inthe Auburn geothermal well Auburn New Yorkrdquo Journal ofGeophysical Research vol 90 no 7 pp 5497ndash5512 1985

[18] C A Barton M D Zoback and K L Burns ldquoIn-situ stressorientation and magnitude at the Fenton Geothermal siteNewMexico determined fromwellbore breakoutsrdquoGeophysicalResearch Letters vol 15 no 5 pp 467ndash470 1988

[19] B C Haimson and C Chang ldquoTrue triaxial strength of theKTB amphibolite under borehole wall conditions and its useto estimate the maximum horizontal in situ stressrdquo Journal ofGeophysical Research vol 107 no 10 pp ETG 15-1ndashETG 15-142002

[20] M Chen Y Jin andGQ Zhang PetroleumEngineering RelatedRock Mechanics Science Press Beijing China 2008

[21] J GDeng Y F ChengMChen andBH YuWellbore StabilityEvaluation Technique Petroleum Industry Press 2008

[22] V Maury and C Zurdo ldquoDrilling-induced lateral shifts alongpre-existing fractures a common cause of drilling problemsrdquoSPE Drilling amp Completion vol 11 no 1 pp 17ndash24 1996

[23] X Chen and C P Tan ldquoThe impact of mud infiltration onwellbore stability in fractured rock massesrdquo in SPEISRM RockMechanics Conference 78241 October 2002


3 Drilling Problems

Three horizontal wells N001H N006H and N002H in theNahr Umr Formation of Halfaya Oilfield had been drilledThe well distributions are both located in the structural longaxis direction The complicated drilling problems of thesethree wells are as follows

When the first horizontal well (N001STwell) encounteredthe Nahr Umr layer there were two sidetracking operationsThe first sidetracking happened at 394126m the SLB screwstuck in the highly deviated interval and the directionaltool dropped in the well The fishing failed which led tosidetrackingThe second sidetracking happened at 409121mthe Nahr Umr Shale collapsed and this led to stickingat 4087m the treatment measures was ineffective and asidetracking operation happened

The second horizontal well (N006ST well) used theorganic salt drilling fluid which has a strong inhibitionWhen drilling 3964m the Nahr Umr Shale collapsed andthe treatment measure for the sticking failed so sidetrackinghappened at 3800m using the vertical well completion

The third horizontal well N002Hused saturated salt waterdrilling but there were many sticks between 3660m and3895m in the Nahr Umr Formation and there were cavingsat the shaking screen

The twowells of the three horizontal wells have sidetrack-ing due to sticking only one horizontal well was drilled suc-cessfully so it illustrates the big effects of wellbore instabilityproblems in the oilfield The wellbore instability has seriousimpact for oilfield drilling and it restricts the explorationand development in the oil field As the development wellsare generally directional wells or horizontal wells and thewellbore instability risk is great wellbore stability analysis isneeded in the Halfaya Oilfield

4 Wellbore Instability Mechanism

41 Character of the Instable Shale Figure 1 shows the loggingdata of the Nahr Umr Formation of N004 well The GRlogging shows that the formations are mainly sandstone andshale The caliper logging shows that there are both stableand instable intervals Compared to the GR logging data thelithology of collapsing interval is shale and the sandstoneinterval is stable According to the interval transit timelogging data the interval transit time of the Nahr Umr Shaleis obviously higher than the adjacent sandstone intervalThe density logging data of the shale are obviously lowerthan the adjacent sandstone interval The reasons for thisphenomenon are the rich internal microfractures drillingfluid and the filtrate seepageThis can be seen from the photoof the Nahr Umr Shale (Figure 2) In addition the shape ofcavings of the Nahr Umr Shale indicates that the shale isenriched in fractures (Figure 3)

The main reason for wellbore instability in hard brittleshale with lots of fractures is as follows [5ndash11] If the sealingcapacity of the drilling fluid is not enough or the ionicconcentration is not enough to balance the formation waterionic concentration the drilling fluid and the filtrate wouldflow into the microfractures under the driving power from

the fluid column pressure difference of drilling fluid and theionic concentration difference This would lead the frictioncoefficients of the fracture plane to decrease the effectivestresses around the wellbore to decrease the formationaround the wellbore to become loose and the support ofthe drilling fluid column to the wellbore wall decrease Thusthe formation fluid will flow into the wellbore During thereaming and back reaming the disturbance of the rigs to theloose formation will lead to wellbore instability

42 Wellbore Instability Analysis In order to solve the well-bore instability of the fractured and hard-brittle shale inNahrUmr Formation the drilling fluid property and engineeringcountermeasures should be taken into account We analyzethe wellbore instability reasons combined with the drillingengineering measures of three horizontal wells in the NahrUmr Formation

When using rational engineering measures the drillingfluid property decides the wellbore stability during drillingto a large extent Table 1 shows the drilling fluid propertyused in these three horizontal wells These three wells usedthree different types of drilling fluid The following can beconcluded from the drilling fluid property parameters in thetable

(1) Based on the mud rheological parameters for theformation with good completeness the rheological param-eters of these three wells are similar and could meet theengineering requirement But for the fractured shale for-mation the rheological parameters of these three wells aredifferent Compared to the other two wells the drilling fluidof N001H well has a low viscosity which is bad for carryingthe cuttings and cavings In addition the drilling fluid withlow viscosity will easily flow into the formation under thepressure difference Therefore the rheological parameters ofdrilling fluid of N002Hwell benefit wellbore stability Usuallyincreasing the drilling fluid viscosity is of benefit for fractureformation

(2) Based on the drilling fluid filter loss the filter lossesof these three wells are similar Because the filter loss ismeasured by the experimental instrument in the laboratorythe results cannot reflect the real formation situation and it isonly a reference index

(3) Based on the drilling fluid ionic concentrationalthough there are not ionic concentration parameters ofN001H well drilling fluid in the daily drilling report accord-ing to the drilling fluid description provided by the drillingfluid service provider the drilling fluid ionic concentrationsof this well could indicate that the ionic concentration of KCLPolymer drilling fluid used in the N001H well is betweenthe concentrations of the N002H well and N006H well theionic concentration of the N002Hwell is the highest the ionicconcentration of the N006Hwell is the lowestWhen the holeis opened the ionic concentration difference of the drillingfluid and formation water is the main driving force thatdrives the free water in the drilling fluid into the formationCommonly the high ionic concentration of drilling fluid isof benefit to prevent the free water in the drilling fluid fromflowing into the formation If the free water in the drillingfluid flows into the formation the formationwill be hydrated


19 21 23 25 27 29 31100 150 200AC (usft)

8 10 12 14 16CAL (in)

3640

3645

3650

3655

3660

3665

3670

3675

3680

3685

3690

3695

3700

0 30 60 90 120 150GR (API)

Dep

th (m

)

Density (gcm3)














2minus mgL 874HCO

3

minus mgL 7263CO3











364510 517 08 02 27 446364983 608 12 04 47 329366600 485 19 03 14 45 434



364510 34 7 48 11 14364983 33 3 40 24 11366600 44 7 49 21












05055

06065

07075

08085

09095

1

0 20 40 60 80 100Immersed time (h)

Stre

ngth

ratio

(im

mer

sed

not i

mm

erse

d)




120590

119903= 119875 minus 120575120601 (119875 minus 119875

119901)

120590

120579= 3120590

119867minus 120590

ℎminus 119875 + 120575 [

120572 (1 minus 2])1 minus ]

minus 120601] (119875 minus 119875

119901)

120590

119911= 120590V + 2] (120590119867 minus 120590ℎ) + 120575 [

120572 (1 minus 2])1 minus ]

minus 120601] (119875 minus 119875

119901)

(1)


FS =120590

119899119905119892120593 + 119862

120591

(2)

And let

119872 = 1 + (FS minus 1) cos2120593 (3)


1and 120590

3

120590

119899=

120590

1+ 120590

3

2

minus

120590

1minus 120590

3

2

sin120593 minus 120572119875119901 (4)


119872(120590

1minus 120590

3) minus sin120593 (120590

1+ 120590

3minus 2120572119875

119901) minus 2119862 cos120593 = 0

(5)



1

11

12

13

14

15

16

0 20 40 60 80 100Immersed time (h)

Col

lapse

pre

ssur

e (g

cm3)



120579gt 120590

119911gt 120590



120579 1205903= 120590

119903 and make 119896 = (120572(1 minus


119875

119888119903= (2119862 cos120601 + (sin120601 minus119872) (3120590

119867minus 120590

ℎ)

+ [120575119872119896 + sin120601 (2120575119891 minus 120575119896 minus 2119896)] 119875119901)


(6)













7 Conclusions





Acknowledgments


References


























19 21 23 25 27 29 31100 150 200AC (usft)

8 10 12 14 16CAL (in)

3640

3645

3650

3655

3660

3665

3670

3675

3680

3685

3690

3695

3700

0 30 60 90 120 150GR (API)

Dep

th (m

)

Density (gcm3)














2minus mgL 874HCO

3

minus mgL 7263CO3











364510 517 08 02 27 446364983 608 12 04 47 329366600 485 19 03 14 45 434



364510 34 7 48 11 14364983 33 3 40 24 11366600 44 7 49 21












05055

06065

07075

08085

09095

1

0 20 40 60 80 100Immersed time (h)

Stre

ngth

ratio

(im

mer

sed

not i

mm

erse

d)




120590

119903= 119875 minus 120575120601 (119875 minus 119875

119901)

120590

120579= 3120590

119867minus 120590

ℎminus 119875 + 120575 [

120572 (1 minus 2])1 minus ]

minus 120601] (119875 minus 119875

119901)

120590

119911= 120590V + 2] (120590119867 minus 120590ℎ) + 120575 [

120572 (1 minus 2])1 minus ]

minus 120601] (119875 minus 119875

119901)

(1)


FS =120590

119899119905119892120593 + 119862

120591

(2)

And let

119872 = 1 + (FS minus 1) cos2120593 (3)


1and 120590

3

120590

119899=

120590

1+ 120590

3

2

minus

120590

1minus 120590

3

2

sin120593 minus 120572119875119901 (4)


119872(120590

1minus 120590

3) minus sin120593 (120590

1+ 120590

3minus 2120572119875

119901) minus 2119862 cos120593 = 0

(5)



1

11

12

13

14

15

16

0 20 40 60 80 100Immersed time (h)

Col

lapse

pre

ssur

e (g

cm3)



120579gt 120590

119911gt 120590



120579 1205903= 120590

119903 and make 119896 = (120572(1 minus


119875

119888119903= (2119862 cos120601 + (sin120601 minus119872) (3120590

119867minus 120590

ℎ)

+ [120575119872119896 + sin120601 (2120575119891 minus 120575119896 minus 2119896)] 119875119901)


(6)













7 Conclusions





Acknowledgments


References































2minus mgL 874HCO

3

minus mgL 7263CO3











364510 517 08 02 27 446364983 608 12 04 47 329366600 485 19 03 14 45 434



364510 34 7 48 11 14364983 33 3 40 24 11366600 44 7 49 21












05055

06065

07075

08085

09095

1

0 20 40 60 80 100Immersed time (h)

Stre

ngth

ratio

(im

mer

sed

not i

mm

erse

d)




120590

119903= 119875 minus 120575120601 (119875 minus 119875

119901)

120590

120579= 3120590

119867minus 120590

ℎminus 119875 + 120575 [

120572 (1 minus 2])1 minus ]

minus 120601] (119875 minus 119875

119901)

120590

119911= 120590V + 2] (120590119867 minus 120590ℎ) + 120575 [

120572 (1 minus 2])1 minus ]

minus 120601] (119875 minus 119875

119901)

(1)


FS =120590

119899119905119892120593 + 119862

120591

(2)

And let

119872 = 1 + (FS minus 1) cos2120593 (3)


1and 120590

3

120590

119899=

120590

1+ 120590

3

2

minus

120590

1minus 120590

3

2

sin120593 minus 120572119875119901 (4)


119872(120590

1minus 120590

3) minus sin120593 (120590

1+ 120590

3minus 2120572119875

119901) minus 2119862 cos120593 = 0

(5)



1

11

12

13

14

15

16

0 20 40 60 80 100Immersed time (h)

Col

lapse

pre

ssur

e (g

cm3)



120579gt 120590

119911gt 120590



120579 1205903= 120590

119903 and make 119896 = (120572(1 minus


119875

119888119903= (2119862 cos120601 + (sin120601 minus119872) (3120590

119867minus 120590

ℎ)

+ [120575119872119896 + sin120601 (2120575119891 minus 120575119896 minus 2119896)] 119875119901)


(6)













7 Conclusions





Acknowledgments


References




























364510 517 08 02 27 446364983 608 12 04 47 329366600 485 19 03 14 45 434



364510 34 7 48 11 14364983 33 3 40 24 11366600 44 7 49 21












05055

06065

07075

08085

09095

1

0 20 40 60 80 100Immersed time (h)

Stre

ngth

ratio

(im

mer

sed

not i

mm

erse

d)




120590

119903= 119875 minus 120575120601 (119875 minus 119875

119901)

120590

120579= 3120590

119867minus 120590

ℎminus 119875 + 120575 [

120572 (1 minus 2])1 minus ]

minus 120601] (119875 minus 119875

119901)

120590

119911= 120590V + 2] (120590119867 minus 120590ℎ) + 120575 [

120572 (1 minus 2])1 minus ]

minus 120601] (119875 minus 119875

119901)

(1)


FS =120590

119899119905119892120593 + 119862

120591

(2)

And let

119872 = 1 + (FS minus 1) cos2120593 (3)


1and 120590

3

120590

119899=

120590

1+ 120590

3

2

minus

120590

1minus 120590

3

2

sin120593 minus 120572119875119901 (4)


119872(120590

1minus 120590

3) minus sin120593 (120590

1+ 120590

3minus 2120572119875

119901) minus 2119862 cos120593 = 0

(5)



1

11

12

13

14

15

16

0 20 40 60 80 100Immersed time (h)

Col

lapse

pre

ssur

e (g

cm3)



120579gt 120590

119911gt 120590



120579 1205903= 120590

119903 and make 119896 = (120572(1 minus


119875

119888119903= (2119862 cos120601 + (sin120601 minus119872) (3120590

119867minus 120590

ℎ)

+ [120575119872119896 + sin120601 (2120575119891 minus 120575119896 minus 2119896)] 119875119901)


(6)













7 Conclusions





Acknowledgments


References



























1

11

12

13

14

15

16

0 20 40 60 80 100Immersed time (h)

Col

lapse

pre

ssur

e (g

cm3)



120579gt 120590

119911gt 120590



120579 1205903= 120590

119903 and make 119896 = (120572(1 minus


119875

119888119903= (2119862 cos120601 + (sin120601 minus119872) (3120590

119867minus 120590

ℎ)

+ [120575119872119896 + sin120601 (2120575119891 minus 120575119896 minus 2119896)] 119875119901)


(6)













7 Conclusions





Acknowledgments


References



























Acknowledgments


References

























researcharticle chemical effect on wellbore instability of

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