Use of Swellable Elastomers to Enhance Cementation in Deep Water Applications

Transcription

1 Use of Swellable Elastomers to Enhance Cementation in Deep Water Applications Bob Brooks, Tim Davis, Frank DeLucia TAM International This paper was prepared for presentation at the Deep Offshore Technology Conference International in Houston, TX, February, 2008 Abstract A lot of time is invested in developing a truly integrated approach that can shorten the planning and study timeframe while reducing uncertainties for drilling in the deepwater arena. Few opportunities present themselves as candidates to implement new technology which provides assurances to these best laid plans. One such opportunity is in the area of cement or zonal isolation. Swellable elastomer packers can provide assurances for zonal isolation when primary cement jobs are difficult, or in critical areas of well construction to ensure long term well integrity. The deepwater environment presents numerous challenges when it comes to cementing casing. One such challenge is at shallow depths, low temperatures, where small differences between pore and frac pressures require special cementing practices. Long openholehighly deviated production intervals present problems with extreme temperature and pressure changes and hole cleaning when displacing primary cement jobs. Too many times a poor primary cement job goes undetected by even the most advanced cement bond evaluation tools. Often it is only after a well is placed on production that data suggests a lack of zonal isolation. The cost of remedial intervention at this point is large compared to the cost of including swellable packers in the initial well completion design. Introduction In the design of any well, there are a number of critical areas that require special design considerations. One area is zone isolation which can be accomplished by performing a quality primary cement job. A good primary cement job is not only essential to isolate zones behind the production casing string, but it is equally important in shallower casing strings to ensure long term well integrity. Another critical area in the design of a deepwater well is wellbore trajectory. Many deepwater wells contain high wellbore deviations at some interval in the trajectory. It is also believed that in future deepwater development there will be an emphasis on drilling extended reach wells. Long deviated open hole sections can make placement of a quality primary cement job extremely difficult. 1

2 Eccentric casing in deviated hole sections causes asymmetric flow geometry which could result in poor mud/filter cake removal during primary cement placement. During the life of a well, an annular cement sheath will be exposed to stresses induced by pressure from casing integrity tests and/or pressure from production/injection. When a well is placed on production, an increase in temperature at shallow depths could induce stresses in the cement sheath at these shallower depths. Technical literature has reported the potential for cement sheath failures due to these stresses 1. A failure in the cement sheath can lead to lost production to thief zones, unwanted water or gas migration, and costly long term well integrity issues. Many of the problems in achieving zone isolation when the primary cement job is less then effective can be overcome by including swellable packers in the casing program. A swellable packer is manufactured using absorbable elastomers which increase in diameter automatically when exposed to well fluids. The well fluids may be drilling mud that was used to drill the well, spacer fluid used during the primary cement job, or produced/injected fluids. Special elastomers are blended to swell in hydrocarbon or aqueous based fluids. As the packer element increases in diameter, the elastomer will make contact with the borehole wall or cement sheath. After wall contact, the elastomer continues to swell producing an interface seal line pressure between the elastomer and borehole wall. A combination of the seal line pressure and the length of the elastomer will provide hydraulic isolation in the areas where there is no cement. The packers should be positioned at depths where zone isolation is most critical. Assuring Primary Cement Jobs There are basically three critical factors in designing a primary cement job; cement slurry design, the position of the casing in the wellbore, and mud displacement ahead of the cement slurry. Out of these three, mud displacement is the most critical and the hardest to control 2, 3. There is no direct way to measure if the mud displacement during the cementing job was effective. Poor mud displacement can leave mud channels or mud cake layers which will prevent zone isolation. There are a number of conditions that can lead to poor mud displacement. The most prevalent causes are: Poor borehole quality leading to excessive wall rugosity, out of gauge sections, and poor flow dynamics, Eccentric casing resulting in an asymmetric flow geometry Poor chemistry between spacer/mud or cement/mud interface Inability to rotate or reciprocate casing. All too often one of these factors are less then optimum. Asymmetric flow geometries result when the casing position in the borehole is eccentric. Under eccentric conditions, a 4:1 velocity difference between the wide side and narrow side can be seen with high viscosity fluids 4. This would 2

3 require high pump rates for good mud displacement. With narrow windows between pore pressures and frac gradients in deepwater, the equivalent circulating densities encountered may prohibit reaching pump rates necessary to displace the near/low side of the annulus. Also the tight liner top clearances often seen in deepwater well construction could create enough back pressure that the desired pump rates cannot be achieved. Inadequate displacement velocities and fluid volumes could lead to bypassed mud on the near side annulus under eccentric conditions. Also contributing to bypassed mud channels is less then optimum fluid rheologies between the cement and drilling mud. Figure 1 shows that when casing is eccentric in an openhole, an asymmetric flow profile during cement placement could leave behind bypassed mud. The bypassed mud could present a flow channel for interzonal communication, which could severely affect well integrity. A deepwater Gulf of Mexico operator had been experiencing poor cement placement on the low or near side of the hole in a deviated wellbore. Past cement evaluation logs showed that there was good cement placement on the high side, while on the low side there were no strong indications of the presence of cement. In order to assure annular isolation, two swellable packers were placed at the most critical areas in the open hole interval. Figure 2 shows a standard bond log presentation over one of the packers. As can be seen the packer with a 15 ft. elastomer seal length was positioned at XX300 feet. The cement bond log shows improved bonding above the setting depth of the packer. The time for the packer to swell was on the order of days, while the cement was designed to reach optimum compressive strength in 30 hours. Including a 15 ft packer in the casing string, acts as a large centralizer. By improving centralization, the flow geometry was such that cement placement improved above the packer. The swellable packer in addition is able to swell on the low side of the hole to assure isolation. Full scale testing under eccentric conditions has shown that a swellable packer under fully eccentric conditions can swell and seal on both the low side and high side of the hole. Long Term Cement Integrity The scenario of displacing the perfect cement job, only to end up with loss of isolation is all too familiar. Failures of the cement sheath and/or a microannulus are believed to be two failure modes that lead to loss of annular isolation. These failures typically do not show themselves until the well has been on production for some period of time. The most common signs that are seen that suggest there is a problem with annular isolation are; increase in water production, loss of production to adjacent zones, and sustained casing pressure. Considerable costs may be necessary just to diagnose the problem, i.e. production logs. Historically, conventional squeeze jobs have been the approach to regain annular isolation. These remedial operations in deepwater require a substantial operating expense. In many cases the cement may have been placed properly, however a failure of the cement sheath still occurred. 3

4 Cement slurry technology has made large advancements over the past ten years. For many cases in the deepwater environment, these slurries are designed to be fit-for-purpose. However, laboratory tests on cement properties as well as cement placement are done on a scaled down basis and under conditions that are not equivalent to actual well conditions. This unfortunately cannot predict a number of real conditions that lead to cement sheath failure. One such condition is tensile load failure. Under most well operating conditions, cement failure occurs under tensile loading 2. The tensile strength of cement is approximately 25% of the compressive strength. The two primary causes of excessive tensile loading are; 1) excessive casing test pressures causing failure in the bottom one-half to threequarters of the casing string, and 2) high temperatures from production in the upper one-fourth to two-thirds of the well 1. Figure 3 illustrates the cement sheath failure. There are a number of approaches within the industry to predict cement sheath failure. The standard model used to predict cement sheath failure consists of three materials, the casing, the cement, and the formation (or casing in the instance of casing cemented inside casing). See figure 4. The mechanical properties (Young s Modulus, Poisson s Ratio, etc) of the casing are known. Lab analyses of the cement mechanical properties can be obtained, and are assumed to be valid downhole after displacement. The formation mechanical properties are the hardest to describe. The formation is less isotropic then either the casing or cement with the potential of unequal horizontal stresses. Complicating the model is the existence of a disturbed near wellbore plastic zone which is a result of the drilling process. Most models only consider forces induced in the cement sheath by the casing in the diametric direction. These models do not consider any potential forces induced by axial movement of the casing. Expansion of the casing caused by fluctuations of pressure and temperature create tangential and radial stresses in the cement sheath. The direction of the radial stress is perpendicular to the axis of the wellbore outward into the cement. The tangential or hoop stress is perpendicular to the radial stress. The highest concentration of radial and tangential stress is found at the casing/cement interface. Preventing these stresses from forming on the ID of the cement sheath would eliminate failures. A simple approach to protect the cement sheath in wellbore critical areas is presented here. There are few options that can be implemented during the life of a well that will completely eliminate the forces that induce stresses which fail a cement sheath. What is proposed is that a fourth material be used in the model explained above that has mechanical properties that can absorb or accommodate casing diametric displacement. This would provide the ability to minimize the formation of destructive stresses in the cement sheath. Figure 5 shows the same model with a layer of elastomer between the casing and the cement. With a swellable packer completely surrounded by cement, excessive stresses formed by pressure and temperature fluctuations are absorbed by 4

5 the compression of the elastomer. Figure 6 illustrates how 20 ft. elastomer seal length can assure 20 feet of undamaged cement, which is adequate to provide hydraulic isolation. The end caps of the swellable packer contribute to the reduction of casing radial displacement. This effectively increases the thickness of metal over the interval of the elastomer seal length, which decreases potential diametric displacement. Figure 7 compares the diametric displacement versus pressure for free 5-1/2 casing versus 5-1/2 casing with a packer installed. As can be seen the amount of movement is greatly reduced. However this amount of movement can still be enough to fail the cement sheath. While the end caps constrain the amount of displacement, the elastomer has the ability to compress to accommodate casing diametric displacement. The end result is that the cement sheath around the swellable packer does not see excessive forces that would create destructive stresses. Figure 8 shows the relationship between the decreases in rubber volume (volumetric strain) versus increasing pressure. The results were taken from confined testing, which represents the packer completely surrounded by cement 6. The end result is when a 20 foot seal length packer is included in the casing string design, there is assurance that if sufficient stresses that can fail cement occur during the producing life of the well, there is a 20 foot section of cement that maintains its integrity. The packers can be placed in critical areas such as but not limited to; Surface or intermediate casing to protect against sustained casing pressure, Between known water and production zones, Between production and depleted zones. Intervals where production zones are expected to deplete at various rates. Microannulus Another cause for the loss of isolation is a microannulus. A microannulus develops when the bond at the casing/cement interface is lost. This can result from pressure and temperature fluctuations. The size of the microannulus depends on the magnitude of the pressure and temperature fluctuations as well as properties of the cement. The formation of a microannulus can result in an annular flow path. A swellable packer has the ability to swell and seal off the microannulus. Figure 9 illustrates how a swellable packer can seal off a microannulus or a void left by a mud channel. Another area where swellable packers can be used to ensure long term well integrity is in wells where liners are planned to be used. In deepwater this includes almost every well. The preferred operation when installing a liner would be to circulate cement up to the casing/liner over lap as the primary seal, and then use a liner top packer as a backup seal. Depending on the well design, this may not always be achievable. In that case, the liner top packer becomes the primary seal. A failure of that seal at some time in the life of the well results in the loss of well 5

6 integrity. A costly workover is required to diagnose and repair a liner top leak. In the deepwater Gulf of Mexico, several operators have recognized the potential risk of depending on the liner top packer as the only seal. A swellable packer can be placed in the casing/liner overlap section to provide a secondary or backup seal to the primary liner top seal. After the cement is pumped, the packer will swell in the fluid that is left in the casing/liner overlap section. Case histories have shown this to typically be cement spacer fluid. Figure 10 illustrates this application. Conclusions Successful placement of primary cement in deepwater wells is challenging because of issues presented by the small differences between pore pressure and formation fracture gradients. Equivalent circulating densities may prohibit circulation rates that are required to assure mud is properly displaced so that mud channels are not created. Deviated wellbores which result in eccentric annulus flow profiles can further complicate proper mud displacement. As part of the ongoing/refinement of deepwater completions to provide assurances against mud channels that can ultimately lead to an annular flow path, swellable packers should be part of the casing design. The swellable packers should be placed in critical areas where they can swell and seal in a mud channel or microannulus. This new approach will greatly improve the ability to obtain long term zonal isolation with or without good cement. Further consideration for swellable packers in a casing/cement design is to protect the cement sheath during the life of the well. Fluctuations in pressure and temperature may induce destructive forces on the cement sheath by the casing. A swellable packer provides a way to constrict and absorb casing diametric displacement due to these fluctuations in pressure and temperature thereby ensuring a competent cement sheath around the packer. This protected cement sheath assures zone isolation as well as long term well integrity. Acknowledgements The authors wish to thank Chevron s deepwater management group for the permission to include the case history of using swellable packers to assure zone isolation and long term well integrity. We also wish to acknowledge C.O. Doc Stokley for his technical review and contribution. References 1. Goodwin K.J., Crook R.J., Cement Sheath Stress Failure, SPE Drilling Engineer, Dec 1992, [SPE 20453]. 2. di Lullo G., Rae P., Cements for Long Term Isolation Design Optimization by Computer Modelling and Prediction, Paper SPE presented at the 2000 IADC/SPE Asia Pacific Drilling Technology, Kuala Lumpur, Malaysia, September Phipps J.S., Ladva H.K.J., Craster B., Caritey J.P., Dargaud B., Design and Evaluation of an Elastomeric Sealant for Use in Primary 6

7 Cementing, Paper SPE presented at the SPE International Symposium on Oilfield Chemistry, Houston, TX 28 February 2 March Moran L., Savery M., Fluid Movement Measurements Through Eccentric Annuli: Unique Results Uncovered, Paper SPE presented at the SPE Annual Technical Conference and Exhibition, Anaheim, California, November Nelson E.B., Guillot D., 2006, Well Cementing, second edition, 147, Schlumberger. 6. Peng S.H., Shimbori T., Naderi A., Measurement of Elastomer s Bulk Modulus By Means of a Confined Compression Test, Paper presented at the Spring ACS Rubber Division Meeting, Chicago Illinois, May, Fig. 1 Mud Channel Left from Poor Cement Placement 5 7

8 Fig. 2 Cement Bond Log over Interval with Swellable Packer Fig. 3 Creation of Stress Cracks in Cement Sheath Due To Fluctuations in Pressure and/or Temperature 8

9 Fig. 4 Standard Stress Model to Predict Cement Sheath Failure 9

10 Fig. 5 Modified Model to Include Elastomer When Predicting Cement Sheath Failure Fig. 6 Swellable Packer Protecting Cement Sheath 10

11 Displacement - Free Casing Casing Expansion With Packer Diametric Displacement - inches Pressure - psi Fig. 7 Free Casing Expansion versus Constrained Casing Expansion Pressure - PSI Volumetric Strain Fig. 8 Example of the Compressibility of Rubber 6 11

12 Fig. 9 Swellable Packer Filling Voids Left By Microannulus Or Mud Channels 12

13 Fig. 10 Liner Top Backup Seal 13