Analysis of an Annular Pressure BuildupFailure During Drill Ahead

P.D. Pattillo, SPE, B.W. Cocales, SPE, and S.C. Morey, SPE, BP America

SummaryWhile drilling ahead in salt on the Pompano A-31 (Gulf ofMexico) wellbore below the 16-in. shoe, the rotary stalledabruptly, and the drillpipe simultaneously became stuck. Subse-quent calipers indicated the 16-in. casing to be deformed onto thedrillpipe at approximately 250 ft.

To the authors’ knowledge, this situation represents the firstinstance of an annular pressure buildup (APB) failure during drill-ing. APB is typically associated with extremes of temperature changeresulting from production operations. In the current instance, thetemperature change is solely from circulating drilling fluid.

This paper provides a detailed post-analysis of the 16-in. casingfailure as follows:

• An overview of the conventional casing design for this well,indicating that normal operating conditions should not have re-sulted in a failure.

• A review of the failure event, substantiated by field measure-ment and photographs.

• An investigation of APB, associated with inadvertently clos-ing the 16-in. casing annulus at the surface, demonstrating themagnitude of the possible resulting thermally induced pressure load.

• Consideration of an alternate failure mode, column buckling,to demonstrate that this failure mode was not active in this wellbore.

• A finite-element model of the drillpipe/16-in. casing/20-in.casing trio indicating that, in addition to the collapse of the 16-in.casing and subsequent sticking of the drillstring, the outer 20-in.casing was also damaged by the event.

The latter item is particularly important because damage toouter strings can be easily overlooked if concentration is on thecollapsed casing and drillpipe fish. A mechanical caliper confirmsdamage to the outer 20-in. string.

Conclusions in the paper center on confirmation of the postu-lated failure mode by field measurement and recommendations foravoiding such an event.

IntroductionWhile drilling ahead at 9,132 ft. on the Pompano A-31 wellbore(Vioska Knoll 989 A-31, OCS-G-6898) below the 16-in. shoe(Fig. 1), the rotary stalled abruptly, and the drillpipe simulta-neously became stuck. An increase of mudflow out of the flowlinesurged over the gumbo buster.

Approximately 500-psi pressure was bled off the 16-in. by20-in. annulus. The fluid initially recovered from the 16-in. by20-in. annulus was a clear, 10-ppg brine, but later changed to a10.5-ppg, synthetic-based mud composition tantamount to thefluid placed above the cement top in the 16-in. annulus.

Tripping the drillstring out of the hole required 60 to 100 kipsat each 83⁄8-in. HWDP tool joint and 150 kips at the uppermost141⁄2-in. stabilizer. Recovery of subsequent stabilizers and the re-maining seven joints of HWDP was aided with drilling jars.

A caliper-logging tool set for a maximum diameter of 113⁄4 in.tagged an obstruction at 253 ft. Logging upward, the calipershowed damage from 242 to 253 ft. The wellbore was temporarilyabandoned with four cement plugs. Subsequent to plugging thewell, pressure testing indicated communication between the 16-and 20-in. casing strings.

The 16-in. casing was cut at 1,399 ft and pulled. The remaining16-in. riser stub, along with the Dril-Quip hanger running tool,were recovered to 1,485 ft. A caliper was then run in the 20-in.casing, thereby indicating damaged casing from 253 to 280 ft.(maximum inside diameter 20.387 in. at 272 ft.) (See Fig. 2.).

Figs. 3 and 4 illustrate the condition of the 16-in. casing re-covered from the vicinity of the obstruction. The ovalized crosssection appears adjacent to a window (presumably) worn by mill-ing before recovery.

Pertinent evidence gathered during the initial investigation andrecovery of the ovalized 16-in. casing includes the following:

• The drillstring stalled abruptly, indicating an instantaneous event.• There is no evidence from prefailure drilling parameters of an

out-of-the-ordinary occurrence.• The recorded circulating temperatures—180°F bottomhole

and 168°F at the flowline—are high (particularly the latter).• The 16-in. annulus valve was closed while drilling the 141⁄2-

in. by 171⁄2-in. hole section.• The depth of the failure is shallow. Given 10.5-ppg drilling

fluid outside the 16-in. casing, an evacuated collapse differential is0.052 psi/ppg-ft by 250 ft by 10.5 ppg�136 psi, as compared tothe API collapse rating for this casing of 1,480 psi.

For future reference, the Pompano A-31 casing run before thefailure is listed in Table 1.

Conventional Casing DesignThe term “conventional casing design” in this context refers to adesign in which the integrity of a single-tubular string is investi-gated without consideration of the interaction of the string withother tubulars. Loads that are associated, for example, with trappedpressures in an annulus between the target string and its neighborsare not considered.

Fig. 5 summarizes the pertinent external pressure design factorsfor loads typical of an intermediate casing string. The currentstring is designed for the lost-circulation load case in which mudused to drill the next hole section is allowed to drop until it reachesa hydrostatic balance with pore pressure in the open hole. Thedepth and corresponding pore pressure used are those that result inthe most severe collapse load case. The evacuation load case isalso shown for information because this load scenario is also usedby operators. Pertinent depths in the figure are 1,486 ft, the sectioncrossover in the 16-in. string (see Table 1) and 2,549 ft, the depthto which the mud column falls in the lost circulation load case.

Although the lower portion of the 16-in. casing, the 97-lb/ftN80 run below 1,486 ft, has a safety factor less than unity underthe evacuation-load case, the failure in this string was in the shal-lower, 84-lb/ft P110 casing. Collapse safety factors for this shal-lower segment of the 16-in. casing are consistently higher than 1.5.

The implication of this information is that, barring an unexpect-edly low-collapse resistance of the subject casing, conventionalcollapse loads should not have failed this string at 242 to 280 ft. Toinvestigate the possibility that the casing opposite this interval hasa lower-than-expected collapse performance, companion joints tothe failed casing were collapse tested, with the results displayed inTable 2. As indicated in the table, the collapse resistance of thecompanion joints is higher than the API minimum collapse ratingof 1,480 psi upon which the safety factors in Fig. 5 are based.

Temperature ModelingOf the evidence outlined in the previous section, one outstandingfeature is the high-surface circulating temperature during drillahead. An attempt was made to match the circulating temperatureswith a commercial thermal simulator.

Copyright © 2006 Society of Petroleum Engineers

This paper (SPE 89775) was first presented at the 2004 SPE Annual Technical Conferenceand Exhibition, Houston, 26–29 September, and revised for publication. Original manuscriptreceived for review 4 June 2004. Paper peer approved 1 May 2006.

242 December 2006 SPE Drilling & Completion

Unfortunately, the capabilities of the software are insufficientto model the fluid system of the drilling rig. As an alternative, thesurface circulating temperature (inlet to drillpipe) was adjusted tothe point where the observed circulating temperature of 168°F waspredicted by the software. Input data for the model are summarizedin Table 3.

Fig. 6 presents the results of the thermal prediction, indicatingnot only the profile outside the drillstring, but also, for later ref-erence, the temperature in the 16- by 20-in. annulus.

Annular Pressure BuildupIn well design, APB refers to the pressure change in a fluid in aclosed annulus. The phenomenon is particularly relevant to off-

shore wells in which annuli can be trapped by terminating a casingstring(s) at the mud line. The ABP phenomenon, however, canoccur in any annulus that is not vented (Halal and Mitchell 1994;Ellis et al. 2002).

Consider a liquid completely filling a closed container. Whenthe temperature of the fluid is increased, it attempts to expand inaccordance with its coefficient of thermal expansion. This volumechange is countered by the rigidity of the container. Resistance tothe free expansion of the fluid induces a pressure increase. Ac-cording to the rigidity of the enclosing walls, this pressure increaseinduces a corresponding change in the dimensions of the container.Equilibrium ensues, involving changes in both the fluid and thecontainer. The incremental annular pressure accompanying achange in temperature is, therefore, a function of the following:

• Mechanical and thermal properties of the annular fluid.• Flexibility of the confining boundary.• Temperature increase.

The Present Case. The 16- by 20-in. annulus in the current wellconstitutes a possibly closed container. First, as mentioned in theintroductory comments, the 16-in. annulus valve was closed whiledrilling the 141⁄2- by 171⁄2-in. hole section. Secondly, the targetedtop of cement for the 16-in. casing is close to the 20-in. casingshoe. Error in cement calculations or application, barite settling inthe drilling fluid above the cement top, or failure to maintainstability of any open hole above the cement could individually, orin concert, contribute to closure of the 16- by 20-in. annulus.

Fig. 1—Schematic of Pompano A-31 at time of failure, all depthsin ft RKB.

Fig. 2—Log-measured displacements of 20-in. casing.

Fig. 3—Photograph of recovered, collapsed 16-in. casing. Fig. 4—Photograph of recovered, collapsed 16-in. casing.

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Of further importance to the APB issue is that a synthetic,rather than water-based, mud was used to drill the 171⁄2-in. holesection. This switch in mud composition distinguishes the current171⁄2-in. hole section from all but one of its counterparts on thePompano platform. The 171⁄2-in. hole section of an earlier well wasalso drilled with synthetic mud. This earlier operation, however,ran a 133⁄8-in., 72-lb/ft, N80 casing (2,670-psi collapse resistance),rather than a 16-in., in the 171⁄2-in. hole.

Modeling Results. A “drill-ahead” scenario, using data describedin Table 4, was used to calculate APB effects on the 16- by20-in. annulus.

The synthetic fluid present in the 16- by 20-in. annulus wasmodeled as an oil-based mud because of limitations in the mod-eling software.

With these inputs, the predicted incremental pressure caused byannular pressure buildup is 3,423 psi (9.6-bbl potential expansionvolume). Compared to the collapse rating of the 16-in., 84-lb/ft,P110 casing (1,480 psi), this value is more than sufficient to ini-tiate collapse (assuming a roughly equal density gradient frominside and outside fluids).

As previously mentioned, one distinguishing fact in the currentscenario is the decision to switch from water-based to syntheticmud. If the previously shown calculation is repeated with 11.6-lb/gal, water-based mud in the 16- by 20-in. annulus, the ensuingpressure caused by APB is 2,395 psi (6.1-bbl potential expansionvolume), which still exceeds the API collapse rating of the innerstring. The following points are important:

• The API collapse rating is conservative, but even using amore modern prediction (Tamano et al. 1985) and targeting aver-age rather than minimum collapse, the rating of the 16 in. is 2,080psi, still less than the predicted incremental APB pressure.

• Both the oil-based and water-based calculations assume acompletely fluid-filled annulus. If any portion of the 16- by 20-in.annulus is void (e.g., gas-filled), that void can serve as an accu-mulator for its volume equivalent of fluid expansion. This reducesthe corresponding expansion pressure. The effect of a void/gas capin the 16- by 20-in. annulus is illustrated in Fig. 6. With an oil-based mud, a gas cap of 4 bbls reduces the APB pressure from3,423 psi to 1,995 psi. A void of approximately 5.5 bbl reduces theincremental APB pressure lower than the API collapse rating andsuggests no failure. The volume capacity of the upper portion ofthe 16- by 20-in. annulus is 0.0921 bbl/ft. Thus, 5.5 bbl corre-sponds to 60 ft.

• There is a significant difference between the oil-based andwater-based results, allowing ample room (e.g., in the presence ofa partial gas cap, as previously mentioned) for failure with the

Fig. 5—Conventional collapse design factors, 16-in. casing.

244 December 2006 SPE Drilling & Completion

synthetic fluid, but not with a water-based fluid. Returning toFig. 7, and using the Tamano et al. (1985) equation to definecollapse, a gas cap with a volume less than 0.81 bbls (8.8 ft.)produces a collapse with either WBM or OBM, a gas cap with avolume between 0.81 and 3.76 bbls (40.8 ft.) produces a collapsewith OBM, but not with WBM, and a gas cap of greater than3.76 bbls is sufficient to avoid a collapse with either annularfluid. The extent of any possible gas cap in the 16- by 20-in.annulus is unknown.

Modeling the Collapse Damage

To fully understand the observed damage to the tubulars recoveredfrom Well A-31, a 2D plane-strain finite-element model of thefailure point was constructed. The model (Fig. 8) consists of con-centric cross sections, starting with the inner string, of 65⁄8-in., 27.7lb/ft (ID�5.901 in.), S135 drill pipe by 16-in., 84.0 lb/ft(ID�15.010 in.) P110 casing by 20-in., 133 lb/ft (ID�18.730 in.)×56 casing.

The mesh is symmetrical along the boundaries of the first quad-rant. In fact, the inner-tube and outer-tube meshes are axisymmet-ric. The middle tube, however, representing the 16-in. casing isassigned a slight ovality to induce collapse when the 16-in. tube issubjected to external pressure. All casing elements are four-node,

reduced-integration plane-strain finite elements. In addition, themesh contains contact elements to model possible interaction be-tween the strings.

Typical results from the analysis are summarized in Figs. 9 and10. Fig. 9 displays successive deformation of the 16-in. casing. InFig. 9a, the initial (e.g., manufactured) ovality of the 16-in. casingis magnified by external pressure in the 16- by 20-in. annulus tothe point that the tube reaches the maximum load it can tolerateand is in the process of collapsing.

Fig. 9b illustrates the fact that the post-buckled deformation ofthe 16-in. casing actually contacts the 20-in. casing first. Thiscontact (see discussion of Fig. 10) momentarily reinforces the16-in. cross section. The driving pressure, however, is sufficient tocause further deformation of the middle tube, leading to its even-tual contact with the inner string of drillpipe. The model repro-duces both the deformation of the 20-in. casing as well as thecontact and seizing of the drillpipe by the 16-in. casing.

Fig. 10 lends additional detail to the deformed plots in Fig. 9,in which displacements at the points of initial contact with the20-in. casing (Point A, Fig. 8) and the drillpipe (Point B, Fig. 8) areplotted vs. the external pressure applied to the 16-in. casing.

Initially, the slight ovality assigned the 16-in. cross-sectionresults in both horizontal (Point A) and vertical (Point B) displace-ments. At a critical value of external pressure, the maximum re-sponse of the 16-in. cross section is reached, and collapse occurs.The post-buckled response of the tube is to suffer additional oval-ization under decreasing pressure.

As deformation of the 16-in. casing continues, it eventuallycontacts the outer, 20-in. tube. Briefly, the 16-in. casing is rein-forced as displacements at Point A become more difficult becauseof the stiffness of the 20-in. cross section. Eventually, however,and at a pressure much less than the initial collapse pressure of the

Fig. 6—Temperature prediction from drill-ahead thermal simu-lation.

Fig. 7—Variation of annular pressure buildup with void in 16-in.×20-in. annulus.

Fig. 8—Undeformed mesh for casing collapse finite-elementmodel.

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16-in. tube, there is sufficient vertical displacement for the tube tocontact the inner drillpipe.

Evidence in support of the previously described model is pro-vided by a caliper run in the 20-in. casing following recovery ofthe inner 16-in. string. Fig. 2 summarizes the damage to the 20-in.casing caused by the collapse of the 16-in. casing as caliper-logmeasurements of maximum and minimum internal diameter. Forreference, the figure also contains (dashed lines) predicted maxi-

mum and minimum diameters of the 20-in. casing at the timethe post-buckling 16-in. casing just touches the drillpipe. (SeeFig. 9c.) The exact displacements of the 20-in. casing should differfrom these benchmarks because of the following factors:

• After initial contact, the 16-in. casing further deforms the20-in. casing as it deforms around the drillpipe. (See the tails of the16-in. displacements reported in Fig. 10.)

• Once the 16-in. casing is recovered, there is a small elasticrecovery of the 20-in. casing.

• Recovery of the 16-in. casing from the wellbore may havefurther deformed the 20-in. string.

The intended message of Fig. 2 is that observed damage of the20-in. casing is consistent with the scenario of the 16-in. casingcollapsing because of APB effects.

A Note on Column Buckling

Early in the failure investigation, the possibility of damage in the16-in. casing being the result of column buckling was investigated.To examine the consequences of column buckling, a drill-aheadload case identical to the one used in the APB analysis was con-structed, the only difference being that for the buckling analysis,the 16- by 20-in. annulus was assumed open. Buckling of a verticaltubular is governed by the so-called effective force:

Fe = Fz − �piAi − poAo�, . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1)

where a negative value of Fe indicates buckling. Thus, lowering po

(e.g., removing the potential for APB by prohibiting generation ofthermally induced pressure in this annulus) reduces Fe, increasingthe likelihood of excess buckling.

Fig. 11 summarizes the results. Only the upper section of the16-in. casing (e.g., the 84 lb/ft, P110 section) is analyzed, becausethe upper and lower sections of the string are separated in terms ofaxial load by a landing ring at the crossover. A worst-case sce-nario, that assumes that all the weight of the upper section islanded on the landing ring, is used in the analysis. The entire 16-in.casing string is buckled, as evidenced by the negative effectivestress (�Fe / [Ao−Ai]). However, nowhere is the von Mises equiva-lent stress (maximum in cross section is displayed), which includesthe effect of bending caused by buckling, in excess of the yieldstress (110,000 psi) of the casing at the failure point.

Finally, and as further evidence that column buckling is not thefailure mechanism in this well, buckling and its associated defor-mations should be more severe in the lower sections of the unce-mented length of the 16-in. casing. (See Fig. 11.) The failure in thiswell occurred near the surface.

Fig. 9—Successive deformation of 16-in. casing from collapsethrough contact of outer and inner tubes. Contours are vonMises intensity.

Fig. 10—Displacements of key locations on 16-in. casing. (SeeFig. 7 for definition of points A and B.)

246 December 2006 SPE Drilling & Completion

Conclusions1. Damage to the 16-in. casing in the subject well is caused by

collapse associated with APB during drill ahead.2. The 16- by 20-in. annulus was closed by (a) closing the annulus

valve at the upper end, and (b) either cement, formation (e.g.,wellbore stability) or barite settling at the lower end.

3. To the best of our knowledge, this is the first-known instance ofan APB-related collapse caused by drilling, rather than produc-tion, thermal loads. The primary source of pressure is the rela-tively high surface circulating temperature.

4. The variation in thermal behavior between an oil-based andwater-based fluid, possibly coupled with the presence of a gascap in the 16-in. by 20-in. annulus, can explain why this prob-lem was not encountered on previous wellbores.

5. Collapse of the 16-in. casing not only seizes the inner drillpipe,but also ovalizes the outer 20-in. casing. The latter effect isconfirmed by a mechanical caliper.

6. Excess bending stress caused by column buckling during drillahead is not the failure mechanism in this well.

NomenclatureAi � tube internal cross-sectional area, [L2], in.2

Ao � tube external cross-sectional area, [L2], in.2

Fe � effective force, [ML/T2], lb.Fz � axial force, [ML/T2], lb.pi � internal pressure, [M/(LT2)], psipo � external pressure, [M/(LT2)], psi

ReferencesEllis, R.C., Fritchie, D.G., Jr., Gibson, D.H., Gosch, S.W., and Pattillo,

P.D. 2004. Marlin Failure Analysis and Redesign; Part 2—Redesign.SPEDC 19 (2): 112–119. SPE-74529-PA. DOI: http://www.spe.org/elibrary/servlet/spepreview?id�74529-PA.

Halal, A.S. and Mitchell, R.F. 1994. Casing Design for Trapped AnnularPressure Build-Up. SPEDC 9 (2): 107–114. SPE-25694-PA. DOI:http://www.spe.org/elibrary/servlet/spepreview?id�25694-PA.

Tamano, T., Mimake, T., and Yanagimoto, S. 1985. A New EmpiricalFormula for Collapse Resistance of Commercial Casing. Nippon SteelTechnical Report 26.

SI Metric Conversion Factorsft × 3.048* E–01 � m

in. × 2.54* E+00 � cmpsi × 6.894 757 E+00�kPa � 0.01 bar*

*Conversion factor is exact.

Phillip D. Pattillo is a Distinguished Advisor with BP America inExploration and Production Technology. e-mail: pattilpd@bp.com. Since 1972, he has worked in the areas of multiphaseflow and tubular and rock mechanics. Pattillo holds a BS de-gree in mechanical engineering, an MS degree in engineeringscience from Louisiana State U., and MS and PhD degrees inengineering science from the U. of Notre Dame. Brett Cocalesis a senior deepwater drilling engineer with BP America in Ex-ploration and New Developments. In the industry since 1989,he has worked primarily in drilling and completion operations inGoM deepwater, the shelf, and land. Cocales holds a BS de-gree in petroleum engineering and MBA degrees from Mon-tana Tech and the U. of Montana. Steve Morey is a tubulartechnology specialist with BP in Houston In the industry since1978, he has worked in drilling and completions in GoM deep-water, the shelf, and the L48. Since 1989, he has consulted ontubular technology for BP worldwide. Steve holds a BS degreein mechanical engineering from the U. of New Orleans.

Fig. 11—Stress state in 16-in. casing caused by column buck-ling.

247December 2006 SPE Drilling & Completion