(79913)_Understanding_Formation_(In)Stability_During_Cementing.

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SPE/IADC 79913

Understanding Formation (In)Stability During Cementing

J. Heathman, U. Tare, and K. Ravi, SPE, Halliburton

Copyright 2003, SPE/IADC Drilling Conference

This paper was prepared for presentation at the SPE/IADC Drilling Conference held in Amsterdam, The Netherlands, 19–21 February 2003.

This paper was selected for presentation by an SPE/IADC Program Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers or the International Association of Drilling Contractors and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the SPE, IADC, their officers, or members. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Society of Petroleum Engineers or the International Association of Drilling Contractors is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of where and by whom the paper was presented. Write Librarian, SPE, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435.

Abstract

Managing formation (in)stability should be an integral part of well construction from drilling through cementing and completion operations. Formation (in)stability while drilling has been recognized and is an ongoing study in the petroleum industry. Most of the emphasis in these studies has addressed the interactions between drilling fluids and formations, as well as, the geomechanical aspects. However, if the wellbore is stable at the end of the drilling phase, but the cement and spacer properties are not optimized accordingly, the formation could be destabilized during cementing. Such an event could negate much of the prior effort toward controlling instability. Destabilization could adversely impact the well construction and overall field development throughout the well’s lifecycle. As the rock material is removed and replaced by a drilling fluid and subsequently displaced by cementing fluids (spacer and cement slurry), stability of the wellbore should be ensured by applying an adequate net radial support to the formation. The borehole pressure exerted by these fluids can counteract the near-wellbore effective stress concentration created while drilling. If the radial support applied to the formation is inadequate, the stress concentration can exceed the formation compressive strength, leading to borehole collapse. On the other hand, excessive borehole pressure can lead to lost circulation problems if the near-wellbore tangential (circumferential) stress and the formation tensile strength are exceeded. As the formation is exposed to drilling and cementing fluids, the near-wellbore effective stress concentration is altered because of the formation fluid’s physicochemical interaction. Such alteration of the effective stresses and formation properties can result in time-dependent stability problems.

Introduction

Wells drilled through young sediments that exist as highly reactive shales and siltstones are an integral part of oil and gas

operations in most parts of the world. Cementing fluids often include various salts (e.g. NaCl, KCl, and CaCl2) for various purposes, such as intentionally affecting (shortening) slurry set times, cementing across salt formations, and supposed protection of productive formations that may contain water-sensitive clays. Historically, salt content in cement slurries has varied from 1 or 2% to saturation with NaCl. Use of KCl and CaCl2 is usually limited to no more than 3 or 4%. However, the use of salts in cement slurries is not consistent with respect to formation issues. The position is frequently taken that the high pH of cement slurry, along with its minimal amount of calcium in solution, will suffice to provide protection in most cases. However, very little actual supporting evidence for this assumption has been found. Furthermore, most documented test reports have been based on regained permeability testing of sandstone cores. Although very meaningful to the understanding of a specific issue, any connection between effects on clays in permeable sandstones and formation (in)stability as related to shales is complicated by precipitation of various calcium salt species from cement slurries.1 The pros and cons of this issue are frequently debated with no clear consensus, and when salts are applied presumably for formation stability purposes, it is frequently done without a true understanding of the method or outcome. Additionally, use of salts in cementing spacers and preflushes is seldom applied.

In addition to salts, there are many other additives in cementing fluids. Polymers of many types (e.g. blends containing HEC, CMHEC, and various synthetic polymers) as well as silicates are frequent components in cement slurries. These additives can serve several functions, including prevention of slurry dehydration and annular bridging during placement, enhanced bonding across permeable zones, rheology adjustment, and as an aid to gas migration control. However, combining salts and fluid-loss additives in the same slurry frequently presents a more complicated and costly scenario because many fluid-loss additives do not hydrate and/or otherwise function as efficiently in the presence of high concentrations of soluble salts. The authors believe that this cost-driven approach to achieving cement slurry fluid-loss values has resulted in the reduction and general elimination of salts in many primary cementing slurries, without a true understanding of the resulting effects on wellbore stability. The success rate of primary cement jobs using no salts or other means for providing formation stability cannot go ignored, but neither can the problems. Therefore, this project is intended to revisit some fundamentals of controlling

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formation instability as related to cementing operations, and to

provide a link to current developments in water-based mud technology regarding the same subject. Experiments presented here show that maintaining formation stability with cementing fluids can be just as important in reducing problem well costs as maintaining formation stability with drilling fluids. This maintenance can be achieved through a combination of osmotic outflow of pore fluid (chemical potential mechanism) and prevention/minimization of wellbore fluid pressure penetration. The data presented show that wellbore fluid pressure penetration can be prevented by generating an isolation membrane on the borehole wall. Penetration can be reduced by minimizing hydraulic diffusivity; the two OBMs, recent developments and understanding of membrane-efficient WBMs have started to overcome these deficiencies in regard to formation stability.2

Problems with Conventional Water-Based Muds, Spacers, and Cements

Past efforts to develop improved WBM for shale drilling have been hampered by a limited understanding of the drilling fluid/shale interaction phenomenon. This limited understanding has resulted in drilling fluids designed with inadequately optimized properties, which are required to prevent the onset of borehole instability problems in shales. Historically, wellbore (in)stability problems have been procedures can also be combined.

Background

Shales are fine-grained sedimentary rocks composed of clay, silt, and in some cases fine sands. For this discussion, shale will be considered a loosely defined heterogeneous argillaceous material ranging from clay-rich gumbo (relatively weak) to shale siltstone (highly cemented). Both types will have extremely low permeability and contain clay minerals. Argillaceous formations like shales make up over 75% of drilled formations and cause over 90% of wellbore instability problems. Instability in shales is a continuing problem that results in substantial annual expenditure by the petroleum industry — in excess of a billion dollars, according to conservative estimates. Shales in the upper hole sections where surface and intermediate casings are set, as well as those overlaying drilled, deepwater reservoirs, are typically geologically young. Generally, these formations are poorly consolidated and can cause a significant proportion of wellbore instability problems.

A drilling fluid system (drilling mud) is an essential part of a conventional drilling process and consists of different solid and fluid components. From the standpoint of the shale, cementing fluids are basically the same. Different components may be added to any of these fluids to help enhance their performance. Main functions of a drilling fluid include the removal of rock material during drilling, imparting hydraulic support to the borehole to help ensure stability, providing lubrication to reduce friction between the borehole surface and drillpipe, cooling the drill bit, etc. Cementing preflushes and spacers removes the drilling fluid in preparation for the cement slurry and separates potentially incompatible drilling fluids. Finally, the cement will serve the ultimate function of zonal isolation and structural support. The properties of all of these fluids are adjusted to account for the changing characteristics of wellbore formations encountered.

In the past, oil-based and/or synthetic-based muds (both referred to throughout this paper as OBMs) have been the systems of choice for difficult drilling. Their application has been typically justified based on borehole stability, thermal stability, fluid loss, lubricity, etc. Today, environmental concerns and the availability of synthetic fluids restrict the use of oil-based muds. As a result, innovative means are needed to obtain OBM performance without negatively impacting the environment. Water-based drilling fluids (WBM) are attractive replacements from a direct cost viewpoint. While conventional WBM systems have failed to match the performance of approached on a trial-and-error basis, going through a costly multiwell learning curve before arriving at reasonable solutions for optimized operations and systems. As will be discussed, the same symptomatic approach has been observed for cementing operations, particularly with reference to leakoff testing. Studies of fluid/shale interactions offer insights into the underlying causes of borehole (in)stability, and these studies suggest new and innovative approaches for designing water-based drilling fluids.3 These concepts and ideas will be expanded in this project to include cementing fluids.

When drilling and cementing with water-based fluids under an overbalanced condition in a shale formation without an effective flow barrier present at the wellbore wall, mud pressure will penetrate progressively into the formation. Because of the saturation and low permeability of a shale formation, penetration of a small volume of filtrate into the formation can result in a considerable increase in pore fluid pressure near the wellbore wall. The increase in pore fluid pressure can reduce the effective wellbore fluid support, which leads to a less stable wellbore condition. Although the exposure time associated with cementing fluids will be much shorter compared to the exposure to drilling fluids, the same potentially destabilizing mechanisms are present until the cement slurry hydrates and filtrate availability is minimal.

Empirical Observations: Field Studies

One of the most common measures for gauging the success of a primary cement job on a surface or intermediate string of casing is a formation pressure-integrity test. This test may be performed as either a leakoff test (LOT) or simply a formation-integrity test (FIT) without going to leakoff. The causes of failed integrity tests are typically attributed to either channeled cement jobs or formation effects. The latter is usually broken down into either exposure to permeability, formation fracturing, or simply formation integrity that is less than predicted. Diagnoses can be difficult and the solution is usually repeated cement squeezes until the required pressure integrity is achieved.

While examining several such coastal wells along the U.S. Gulf of Mexico where successful shoe integrity tests were difficult to achieve, a comparison of caliper logs above and below the casing shoe depth frequently revealed a discontinuity. This discontinuity consisted of a large washout below casing shoes set in shales. Fig. 1A shows an average hole size of 12 1/2 in. before 9 5/8-in. casing was run into the well, which had been drilled with a well-inhibited WBM. Fig. 1B shows the caliper section just below the 9 5/8-in. shoe, with

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SPE/IADC 79913 a washout in excess of 15 in. The lithology across this section (approximately 100 ft) had no appreciable change as indicated by gamma ray and resistivity logs. This formation was known to be composed of water-sensitive shales. The washouts were initially assumed to be caused by high flow velocities during the cement job and drilling damage during the subsequent drillout of the squeeze jobs. However, a review of the cementing reports did not reveal any excessive velocities or other rational explanation for the severe washouts. Consequently, the conventional assumption that the washouts were mechanically induced became suspect.

Recent work by Gdanski investigates the effects of various concentrations of high-pH solutions with and without KCl and NaCl on clays.5 While this work is focused on formation damage during stimulation treatments, and as such, is deficient in the manner described previously insofar as extending the interpretation of regain permeability testing to the understanding of shales, the basics of clay chemistry interactions with these types of fluids would be expected to be more or less consistent with that of cementing fluids. This line of reasoning is also consistent with prior literature on the subject of shale and fresh water cement slurry interactions. Not yet fully realizing the fluid/shale physicochemical effects, a trial-and-error approach was used at this point, based on combining the findings from Gdanski, conventional shale swelling tests (shown in Table 1), and field observations thus far. In this area and other well locations in the coastal Gulf of Mexico being scrutinized for problematic LOT/FIT issues, various concentrations of salts were added to the cementing spacers and slurries. The intention of the salts being to at least eliminate the potential detrimental effects of fresh water. Figs. 2A and 2B provide a similar comparison on an immediate offset well to the logs shown in Figs. 1A and 1B. No changes were made in the mud or cementing programs between these two wells, except for the addition of 4% KCl to all spacers and cementing fluids on the offset well. The severe washout was no longer present, and this offset was the first well in which the operator obtained a successful LOT without squeezing. Several such cases have since been documented with similar results. Although these cases may seem to present only circumstantial evidence, when coupled with the tests presented in the remainder of this paper, they provide a strong argument for adjusting the chemistry of cementing fluids for formation stability.

Fundamental Driving Forces and Elevation of Near-Wellbore Pore Pressure

The mechanisms that influence fluid (water) transport are differences between shale and wellbore fluid hydraulic pressure, chemical potential, electrical potential, and temperature.

The interaction process and the mechanisms of transport for shales exposed to water-based fluids can be quite different and complex. The molar free energies of all the constituents within the shale and the water-based fluid provide the driving forces that result in the transfer of water, cations, anions, etc. The sum of all the flow phenomena mentioned can result in a net flow. Equilibrium conditions will be dictated by the sum of these driving forces, which can generally be described by the relationship

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Jv = k/µ ( Ph- Po)

Where

- Jv = net flow - k permeability - µ = viscosity

- Ph = overbalance driving force

- Po = sum of other driving forces such as osmotic

and thermal

The difficulty is in the mathematical treatment of these coupled physicochemical interactions between the water-based fluid and shale. Several investigators have used the nonequilibrium thermodynamic approach in the treatment of the transport process in shales.3,4 This approach allows the incorporation of cross effects between different phenomena, such as flux of a solution with different ionic species caused by the hydraulic gradients and/or chemical potential gradient of that species, as well as thermal and electrical potential.

In most cases, however, the two most relevant mechanisms for water transport in and out of shale are: (1) the hydraulic pressure difference between the wellbore pressure (equivalent total fluid column density) and the shale pore pressure, and (2) the chemical potential difference, i.e., water activity between the wellbore fluid and the shale.

Osmotic Semipermeable Membrane

The fine pore size and negative charge of clay on pore surfaces cause argillaceous materials to exhibit membrane behavior. The efficiency is a measure of the capacity of the membrane to sustain osmotic pressure between the wellbore fluid and shale formation. A mathematical representation to describe the driving force for the movement of water by an

osmotic (flow) mechanism is shown in Equation 1. =

RT Awdf V ×ln =±(σ× Pp)=± Aσ×(P Pp)……………(1) wsh

Where

- Awdf = water activity of the wellbore fluid that can be

estimated by various means, most notably, partial vapor pressure determination, boiling point elevation, or directly using a hygrometer

- Awsh = water activity of the shale pore fluid that can be

measured (for preserved shale cores) by partial vapor pressure determination - Pp = far-field pore pressure - P = near-wellbore pore pressure

- σ = the membrane efficiency term, specific to a shale-

drilling fluid or cementing fluid system

The concept of reflection coefficient6 i.e., membrane ideality, has been previously introduced to handle “leaky systems”, including WBM-shale systems used for borehole stability applications.3 For water-based fluid/shale systems, membrane efficiency (reflection coefficient) is not a clearly defined term (unlike an oil film on shales present in invert oil

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emulsion systems). The membrane efficiency of shale/fluid

systems is due to a difference in mobility of water and solutes (ions) in shales. For shales, when the mobility of solutes is lower than that of water, the membrane is “non-ideal” or “leaky.” The important point is that a nonideal membrane does not entirely restrict the transport of solutes.

If the water activity of the wellbore fluid is lower than the formation activity, an osmotic outflow of pore fluid from the formation, caused by the chemical potential mechanism, may reduce the rise in pore pressure caused by wellbore fluid pressure penetration. If the osmotic outflow is greater than the inflow caused by wellbore fluid pressure penetration, there will be a net flow of water out of the formation into the wellbore. This can result in the lowering of the pore fluid pressure below the in-situ value. The associated increase in the effective wellbore fluid support can lead to an improvement in the stability of the wellbore.

One of the essential parameters that can be adjusted to increase the osmotic outflow is membrane efficiency. The osmotic outflow increases as membrane efficiency improves. In most conventional water-based fluids, the membrane efficiency is low.3,8 Therefore, even if the water activity of the drilling and cementing fluids is maintained significantly lower (with a high salt concentration) than the shale water activity, the osmotic outflow may be negligible because of the low membrane efficiency. The main objective of this project was to identify and understand the interactions between water-based cementing fluids and shale formations. This information should facilitate the design of cementing fluids to help reduce the risk of formation instability during the cementing process. Pressure transmission/chemical potential tests were performed on shale samples to evaluate various compounds for their membrane generation capacity. Details of the experiment and examples of the results are presented in the following section.

Screening Tests for Membrane Efficiency

The screening tests were designed to study time-dependent alterations in shale properties as a result of exposure to drilling and cementing fluids. The experiment consists of confining well-preserved shale samples under geo-static stress and then circulating (under confined dynamic conditions) test fluids at the upstream side of the sample. Change in the downstream pressure is measured simultaneously. The upstream pressure may be increased to simulate overbalance conditions. The application of very high pressure simulates downhole conditions where overbalance is maintained to provide the formation with an effective hydrostatic support. The downstream pressure changes indicate changes in the sample pore pressure. Membrane efficiency is given by the ratio of the maximum differential pressure across the sample and the theoretical osmotic pressure for an ideal semipermeable membrane of the test solution/shale system.

Experimental Setup

A schematic of the membrane efficiency screening test cell is provided in Fig. 3. The screening equipment has six test cells with a confining pressure and pore pressure capacity of 35 and 20 Mpa respectively. Each test cell has an associated test solution cylinder that enables up to six different solutions to be tested simultaneously. This configuration also provides independent control of each test’s start and termination. Two pore fluid cylinders are provided to avoid interruption to the tests when the fluid runs out after switching from one cylinder to the other. Separate high-pressure gas cylinders provide the upstream pressure (test solution) and downstream pressure (pore fluid) that are controlled by high-pressure regulators. The confining pressure is applied with a pump incorporating an accumulator. The upstream pressure of the six test cells is monitored by a single-pressure transducer, while the downstream pressure of each cell is monitored by a separate pressure transducer. Circulation of the test solution is adjusted with the dial gauge of a metering valve at the upstream end of each cell. The entire membrane efficiency-screening equipment is placed in a constant temperature facility to control and maintain constant test temperature.

Summary of Test Procedure

Shale samples of nominally 25 mm diameter and 10 mm long were used in the screening tests presented here. Tables 2 and 3 provide the physical properties and pore fluid composition of the test shale, respectively.10 The experimental procedures for the tests are as follows:

a. Backpressure Saturation. Apply a confining pressure of

20 MPa and a backpressure of 10 MPa with simulated pore fluid at the upstream end of the sample. The downstream pressure increases to above 10 MPa during this stage.

b. Consolidation. The excess fluid/pressure is allowed to

drain/dissipate and the sample is assumed to be essentially consolidated when the change in the downstream pressure is less than 50 kPa/hour.

c. Pore Fluid Pressure Transmission. Upon consolidation

of the sample, increase the upstream pressure to 15 MPa. When the downstream pressure increases by more than 50%, reduce the upstream pressure to 10 MPa.

d. Reconsolidation. Allow the excess pore pressure inside

the sample to dissipate.

e. Test Solution Pressure Transmission. Following the

equilibration of the downstream pressure with the upstream pressure (or stabilization of the downstream pressure), displace the simulated pore fluid at the upstream end with the test solution. Ensure that the volume of test solution pumped is at least twice the volume of pore fluid in the line and upstream platen. Increase the upstream pressure to 15 MPa. Allow the downstream pressure to increase and stabilize.

f. Displacement of Test Solution with Lower Activity

Solution. Following the equilibration of the downstream pressure with the upstream pressure (or stabilization of the downstream pressure), displace the test solution with the lower water activity solution (either salt added to test solution or saline solution).

g. Test Solution Membrane Generation. Circulate the

lower water activity solution at 0.25 ml/hr. Terminate the test when a maximum decrease in the downstream pore pressure is observed.

Discussion of Results

The pore pressure transmission tests were run on various fluids as described in Table 4. Test results are provided in

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SPE/IADC 79913 Figs. 4 through 10. Fig. 4 first shows the net effect of 1% KCl brine on the shale after it was stabilized by 8% NaCl. Due to the imbalance in the salinity, the 1% KCl brine resulted in a net flux of water into the shale as exhibited by the increase in pore pressure. Each subsequent increase in KCl was then able to reduce the pore pressure, with 8% (slightly over 1 molar equivalent) returning the pore pressure to its original state. Higher concentrations of KCl resulted in a reduced pore pressure, indicative of a net flux of water flowing out of the shale.

The sequence of fluids in Fig. 5 shows that the polymeric fresh-water-based cement spacer showed a very slight upward trend in pore pressure. Adding KCl to the next sequence resulted in a net decrease in pore pressure starting as soon as the exposure began. Although the pore pressure changes in this test are not significant in magnitude, the key finding is that net flux is no longer contributing to destabilizing the shale. Keep in mind that these tests were run at room temperature and the fluid mobility typically increases as a function of increasing temperature. Fig. 6 shows the same trends when testing cement filtrate.

The tests shown in Figs. 7 and 8 are slightly different in that the shale was sequentially exposed to a sodium silicate preflush (Fluid D), fresh water, and cement filtrate as would occur during a cementing job. Exposure to the sodium silicate resulted in an immediate and more pronounced decrease in pore pressure, compared to the previous tests. As soon as the sodium silicate was displaced by water and then cement filtrate, the pore pressure increased instantaneously and continued upward to a level greater than the overbalance. This behavior could result in a net destabilizing effect on the shale during cementing, especially if conditions are such that the shale can continue to pull filtrate from the unset cement slurry. Fig. 8 is a repeat of the test in Fig. 7, but with KCl in the cement filtrate. This test likewise shows the sudden increase with exposure to the fresh water spacer, but upon being displaced by the KCl-laden cement filtrate, the pore pressure stabilizes for several days. The upward trend resumes later when the ionic imbalance resumes, but this time period would exceed that of the cement hydration time.

Based on previous tests reported by Tare et al., the swelling tests shown in Table 1, and the results of Figs. 4 through 8, the issue to address next is whether salt is needed in cementing fluids, or can polymers play this role, or is the optimum system a combination of both salts and polymers. Other additives, such as glycols, may also be considered candidates in cementing fluids for the purpose of providing shale stability. Figs. 9 and 10 address only the cement filtrate effects with the same salt loadings, but with polymers added. While the pore pressure trends exhibited a net downward trend for both polymer tests, these two tests cannot differentiate between the effects of the salt and the effects of the polymer. The lack of negative results indicated by the swelling data of Table 1 shows that further testing will be needed to better quantify the application of polymers to efficiently affect fluid transport.

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Conclusions

Based on the results of the tests conducted in this project, the following conclusions can be drawn:

Fresh water cementing fluids could potentially

increase near-wellbore shale instability caused by unhindered fluid pressure penetration.

While adopting the practice of adding low

concentrations of salts has been further quantified as being a positive step toward contributing to formation stability, salt solutions alone may not provide sufficient membrane efficiency, as is evident from the pore pressure transmission tests. Near-wellbore shale instability can be mitigated by

optimizing the properties (activity and membrane efficiency) of cementing fluids. In addition to long-acknowledged mud-removal

attributes, sodium silicate preflushes can play a much larger role in the cementing process by contributing to a higher membrane efficiency. Following a sodium silicate preflush with a fresh

water spacer can allow efficient transfer of water from the wellbore fluid into the shale, resulting in a time-dependent increase in near-wellbore pore pressure and a corresponding decrease in shale stability. Combinations of salts and sodium silicates in

cementing fluids can provide a simple and economical means for managing shale instability during the cementing process.

Acknowledgements

The authors would like to acknowledge Halliburton for permission to publish this paper. We also recognize Chee Tan, CSIRO, and Westport Technology International for providing test support, and Dorse Walton of Cabot Oil & Gas for providing well data.

References

1. Gambino, F.E. et al.: “Experimental Study of Fluid/Rock

Interaction Caused by Drilling and Cementing Filtrates in Carito Field,” paper SPE 65004 presented at the 2001 International Symposium on Oilfield Chemistry, Houston, Texas, 13-16 February 13-16.

2. Tare, U.A., Mody, F.K. and Tan, C.P.: “Mitigating Wellbore

Stability Problems while Drilling with Water-Based Muds in Deepwater Environments,” paper OTC 14267 presented at the 2002 Offshore Technology Conference, Houston, Texas, 6-9 May.

3. Mody, F.K. and Hale, A.H.: “A Borehole Stability Model To

Couple the Mechanics and Chemistry of Drilling Fluid/Shale Interaction,” paper SPE 25728 presented at the 1993 IADC/SPE Drilling Conference, Amsterdam, The Netherlands, 23-25 February.

4. Sherwood, J.D.: “Biot Poroelasticity of a Chemically Active

Shale,” Proc. R. Soc. Lon. A. 440, 365, (1993).

5. Gdanski, R.: “High-pH Clay Instability Rating,” paper SPE

73730 presented at the 2002 International Symposium and Exhibition on Formation Damage Control, Lafayette, Louisiana, 20-21 February.

6. Staverman, A.J.: “Theory of Measurement of Osmotic

Pressure,” Recueil des Travaux Chimiques des Pays-Bas, v.70, (1951) 344-352.

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7. van Oort, E., Hale, A.H., Mody, F.K. and Roy, S.: “Critical

Parameters in Modeling the Chemical Aspects of Borehole Stability in Shales and in Designing Improved Water-Based Shale Drilling Fluids,” paper SPE 28309 presented at the 1994 Annual Technical Conference and Exhibition, New Orleans, Louisiana, 25-28 September.

8. Tare, U.A., Mese, A.I. and Mody, F. K.: “Interpretation and

Application of Acoustic and Transient Pressure Response to Enhance Shale (In)Stability Predictions,” SPE 63052 presented at the 2000 Annual Technical Conference and Exhibition, Dallas, Texas, 1-4 October.

Table 1—Results of Reconstituted Shale Swelling Exposure Testing

Table 2—Physical Properties of Test Shale

Table 3—Pore Fluid Composition of Test Shale

Table 4—Cementing Fluid Descriptions

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Fig. 1A—Hole section above 9 /8-in. casing shoe averaged 12.5 in.

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Fig. 1B—Severe washout in rathole below 9 /8-in. casing shoe.

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Fig. 2A—Offset well, hole section above 9 /8-in. casing shoe averaged 12.3 in.

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Fig. 2B—Offset well, no washout in rathole below 9 /8-in. casing shoe.

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Fig. 3—Test cell of the membrane efficiency-screening equipment.

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Fig. 4—Net effect of 1% KCl brine.

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Fig. 5—Pressure transmission test solution: fluid C. Chemical potential solutions: fluid C (no salt), fluid C (with KCl).

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Fig. 6—Pressure transmission test solution: fluid A. Chemical potential solutions: fluid A (no salt), fluid A (with KCl).

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Fig. 7—Pressure transmission test solution: fluid D. Chemical potential solutions: fluid D (no salt), water and fluid (no salt).

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Fig. 8—Pressure transmission test solution: fluid D. Chemical potential solutions: fluid D (no salt), water and fluid A (with KCl)

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Fig. 9—Pressure transmission test solution: fluid A (no salt). Chemical potential solutions: fluid A (no salt),

fluid A (with polymer and salt).

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Fig. 10—Pressure transmission test solution: fluid A (no salt). Chemical potential solutions: fluid A (no salt), fluid A (with salt, glycol, and polymer).

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