Cementing across salt formations

Using cements of low or high salt concentration appropriately makes drilling through salt less risky.

Bryan Simmons, BJ Services

The US Gulf Coast contains the largest known deposits of salt in the world, Fig. 1.¹ Almost 60% of these salt zones remain unexplored. The areas that have been explored in the Gulf of Mexico range from the Ewing Banks area to the Mississippi Canyon area, Fig. 2.² There are also more than 400 underground salt storage caverns in 27 states and Canada with a capacity to hold over 3 Tcf of gas, Figs. 3 and 4.^3,4 The importance of these salt structures and the potential they represent to future oil production and gas storage have become very significant with declining oil reserves. An article describing sub-salt exploration in the GOM explains the industry attention focused on sub-salt formations: “For 45 years, exploration and development drilling in the Gulf of Mexico stopped when salt was encountered at objective depths. Then in the 1980s, quality reservoir rock, not visible on seismic, was discovered more than 1,000 ft below salt sheets. Since then, encouraged by prolific discoveries and aided by improvements in seismic acquisitions and processing techniques, companies are investing millions of dollars in exploring the sub-salt play.”²

Whether the project is cementing an oil well or a gas storage well, cement sheath failure can increase expenses and decrease assets. Cement integrity loss can cause gas reserves loss, unsafe operations, premature water production, extra cost of unplanned remedial work and well shutdown to comply with government regulations. This article focuses on the dynamics of cementing across a salt section and the reasons why salt should or should not be used to obtain the best cement design.

IMPORTANT PARAMETERS

When cementing across a salt section, several parameters need to be assessed. Salt identification is important. Is the salt a halite, anhydrite, bischofite or carnalite? In the US GOM, most salt formations are assumed to be about 97% pure halite.⁵

Mud system composition (oil-based, water-based, synthetic, salt-saturated, etc.) needs to be determined as well. Salt dissolution during drilling can be controlled by use of a highly salt-saturated water-based or oil-based mud. With a highly saturated water-based mud, hole enlargement can be a problem unless the mud is heated to maintain a saturated mud at all times during circulation.⁶ Oil-based mud can help eliminate the potential for hole enlargement, but may require increased reaming time and result in minor stuck-pipe incidents in the resulting gauge hole. Freshwater pills have been used to free stuck pipe in salt formations when drilling with oil-based mud.⁵

The wellbore temperature and pressure profiles are other factors to consider. Accurate BottomHole Static Temperature (BHST) is essential when planning cement testing. The low temperatures of the deepwater environment and the high temperatures of the HPHT environment cause changes in cement properties and rheologies and their ability to perform under these conditions. Offset well information along with temperature logs are helpful in determining BHST. Software can help determine the bottomhole circulating temperature for cement testing purposes. Wellbore bottomhole pressure, frac gradient and pore pressure are important pieces of information about the pressure profile when trying to model the performance of the cement design in the wellbore. Software can also model flow regime, placement time, mud removal, frac gradient, centralizer spacing and lift pressures while cementing. Accurate pore and frac pressures are required for proper modeling of the cement in the wellbore before performing the job.

Casing string purpose is another important factor. The intended casing string and surrounding formation will determine the type of cement and additives required for proper isolation of the annulus. In some cases, gas migration cement design may be required to help prevent any sustained casing pressure problems in the future. Liners will require a different cement testing schedule from a long string of casing, to allow for the setting of the liner packer and reversing out of any excess cement above the liner packer.

Cement purpose needs evaluation, whether it is isolation of aquifers, gas migration control or as an annular seal. To minimize salt movement, cement slurries should be designed with shorter periods of gel strength development and rapid compressive strength development that will adequately stop salt formations from creeping. This may entail using different additives to control gas, enhance compressive strength and give expansion properties to cement, and different concentrations of salt for compatibility. The most common functions of the cement sheath across the formation are to reduce the risk of point loading of the casing and to ensure shoe integrity so the well can be deepened as soon as possible.⁷

SALT DISSOLUTION

After the basic considerations have been assessed, the effect of the cement’s fluid dynamics and chemical effects on the salt formation needs to be studied. When cementing across a salt zone, salt dissolution will usually occur. Salt dissolution is the washing away of the formation salt during the cementing process. Obtaining formation samples will help to determine the salt’s reactivity to the cement. The amount of salt dissolution depends upon the amount of salt in the cement, the rheology of the cement and the pump rate.

Of the three, pump rate is the most important. Less salt is dissolved at plug flowrates than at laminar flowrates, and sufficient salt can be dissolved at laminar and turbulent flowrates to increase the final salt concentration to greater than 5%, depending on the annular velocity and exposure time. The salt dissolution rate at plug flowrates yields a cement slurry with a salt concentration of 3–5% at exposure times normally encountered in the formation.⁸ Pumping in laminar or turbulent flow results in a significant increase in salt dissolution.⁹

It is also important to note that salt dissolution can occur even after the final set of the cement, through the exchange of ions between the cement filtrate and the salt formation. Understanding the effects of salt dissolution is the first step in designing an optimal cement system. Salt dissolution can cause adverse effects, including the creation of a micro-annulus between the cement and the formation, rheological changes to the slurry, bulk shrinkage of the cement, openhole enlargement and adverse reactions to certain cement additives.

A key factor to understand when cementing across a salt is the BoreHole Closure Rate (BHCR) of the salt formation. The BHCR is the movement of the salt formation primarily due to temperature and stress differentials. BHCRs reported while drilling in massive salt formations can exceed 0.5 in. in 12 hr.7 Because cement loses its hydrostatic pressure after it enters the set phase, the salt is allowed to move inward. If the BHCR of the salt is sufficient, then a micro-annulus created by salt dissolution can be sealed by the formation, and low-salt cement can be used. The sealing of the micro-annulus won’t occur immediately, so care should be taken if gas is present. If gas migration is an issue, then a salt-saturated gas control system should be used. If the BHCR of the salt formation is not sufficient, then salt-saturated cement should be used to prevent micro-annulus problems from developing. It’s important not to confuse the borehole closure rate with creep rates. Creep rates average about 2.5–3 in. per year for the GOM.⁷ Another important factor to consider is the annular clearance between the casing and the formation. The optimum annular clearance for successful cement placement is 1.5 in.¹⁰

CEMENT DESIGN

After the wellbore and fluid dynamics have been investigated, the cement design begins. There are several factors to consider when deciding whether to use high- or low-salt cement. While a high salt concentration in cement will help prevent or slow the salt dissolution rate, other factors will help determine whether a high salt concentration is the optimal choice.9 The main advantages attributed to salt-saturated slurries are greater adherence to salt formations, greater resistance to chemical attack, reduced tendency for gas migration during setting and less dissolution of the salt formation.

The main disadvantages attributed to salt-saturated slurries are retardation of the cement due to salt and long wait-on-cement times, reduced compressive strength due to salt, ion exchange effects due to salt, cement bulk shrinkage, reduction in additive performance—especially fluid loss additives—and problems concerning rheology control in slurries.

Research has been conducted to determine the retarding effect of salt dissolution into the cement design. The results show that salt-saturated cements generally have longer pump times and exhibit slower compressive strength development.⁷ However, low-salt slurries that were exposed to salt dissolution while being placed into the wellbore did not suffer from retardation effects.¹¹ Lab investigation shows that salt-free cement slurries can be placed across salt sections with final salt concentrations of less than 10% as a result of salt dissolution. The dissolution rate of the salt at plug flowrates yields a cement slurry with a salt concentration of 3–5%, depending on exposure time.⁸ The salt dissolution rate at laminar and turbulent flowrates can increase the salt concentration to greater than 5% depending on exposure time. By using a low-salt (3–5% KCl) cement system, the total amount of salt in the cement falls into the neutral range with the addition of 3–5% formation salt. It is important to remember that low salt concentrations tend to accelerate cement. Care should be taken using neat cement across a salt section because 3%–5% salt dissolution can accelerate the cement set.

Many engineers have investigated the effects of salt on compressive strength development in great detail. The general consensus is that salt-saturated cements take longer to develop compressive strength. Conversely, low-salt slurries develop compressive strength faster. Faster compressive strength development is usually required to protect the casing against the flow of plastic salts. It’s important to note that faster, not higher, compressive strength is the key. Research into compressive strength development has shown that cement systems will become more flexible and ductile by lowering compressive strength. Higher compressive strength development can create cement that is more brittle and susceptible to cracking and micro-annulus problems. Cements that possess a high Young’s modulus are more susceptible to damage caused by pressure and temperature change.12 By gathering Young’s modulus and Poisson’s ratio numbers and then inserting them into software, a model can be run showing the competency of a cement system over time, Figs. 5 and 6. The key is to design a cement system with a low Young’s modulus (about 1.029), a high Poisson’s ratio (at least 0.205), good tensile strength (300–350 psi) and good compressive strength (2,500–3,500 psi).

Another important factor is the ion exchange between calcium and magnesium found in brines associated with some salt zones. These have been found to cause severe gelation and long-term chemical attack by magnesium ions, increasing degradation of the cement.¹¹ The presence of magnesium anhydrites is common in West Texas. In contrast, research has shown that salt encountered along the US Gulf Coast is very pure, often 97% mineral halite, and won’t cause the ionic exchange problems more common in other formations.

Oil well cements undergo some degree of cement hydration reduction. This “shrinkage” is attributed to the fact that the volume occupied by the initial cement and water is greater than the volume occupied by the set cement and remaining water. Cement with medium to high levels of salt behaves differently under pressure and temperature than cements with no salt. Salt cements have the advantage of locking the salt into the cement filtrate matrix. As the cement dehydrates under a confining load, the salt crystals take up more room in the cement than when they were in solution. Salt crystallization reduces the amount of shrinkage and in some cases can cause bulk expansion of the cement. This process would be affected by the salt solubility in the cement filtrate as a function of temperature. Without the confining load and lower-salinity water with which to exchange ions, the cement would build up so much stress that after time it would fail from the inside out. If the expansion caused by the salt crystals doesn’t help seal the annulus, then the shrinkage can be offset by adding post-hydration expansion additives to help prevent this problem. Cement hydration reduction is normally about 4% of the volume of the cement.¹²

During well life, the cement will be subjected to many changes, Table 1.¹² The extreme operating conditions that occur in gas storage and gas producing wells could cause the cement sheath to fail, resulting in fluid migration through the annulus. Cement failure modes over the life of the well include debonding, cracking and plastic deformation. Failure of the cement sheath is most often caused by pressure- or temperature-induced stresses inherent in the well operations. This emphasizes the need to address short- and long-term cement properties when designing for life of well, Table 2.¹²

TABLE 1. Example of operations and events during well life

TABLE 2. Short- and long-term properties required of cement

These failures result in sustained casing pressure problems. To help reduce the risk of cement failure, the cement should perform under both short-term and long-term wellbore changes in temperature and pressure.

CONCLUSIONS

The cement sheath across salt formations functions to reduce the risk of point loading of the casing and to ensure shoe integrity tests so that the well can be deepened as soon as possible.

Compressive strength development is critical in formations containing flowable salts. Plastic salt flow can cause point loading or casing collapse. To minimize this problem, cement should be designed with shortened periods of gel strength development and rapid compressive strength development that will adequately stop the salt formation from moving inward.

Dissolution of salt does occur during displacement of the cement, causing some washout of the wellbore. Cement designs with small concentrations of salt (5%), with higher rheologies and pumped in a plug flow regime can help reduce the amount of salt dissolution caused by the cement as it is placed in the annulus.

Salt contamination of cement has less effect on retardation than cement prepared with salt in the design. Therefore, the retarding influence of salt is reduced significantly when the salt is dissolved in the cement slurry at a later stage. Low concentrations (3–5% by weight of water) of KCl should be used in place of NaCl in cements across salt formations and water-sensitive formations. Research suggests that 3% KCl cements have exhibited slurry properties and downhole set properties superior to those of salt-saturated cements.

Salt-saturated cements should be used only when findings suggest that in critical sections the salt flow is not fast enough to close the micro-annulus caused by salt dissolution after placement within a reasonable time. Post-expansion cement additives, fluid loss additives and compressive strength enhancement additives have been developed that will help solve the micro-annulus issue and provide good fluid loss properties and speed compressive strength development.

Salt-saturated cements are used to cement casing across and into salt domes that will be solution-mined and gas storage caverns. The salt-saturated cements are generally used in these cases to reduce the risk of long-term isolation issues between the storage caverns and the freshwater zones above.

Spacers should incorporate salt into the design. The amount of salt can vary from 5% KCl to salt saturated. The primary purposes of spacers are mud removal before cementing and to keep the drilling mud away from the cement. In salt environments, this is generally true, but with a special exception. Since turbulent flow regimes tend to cause more salt dissolution, it is better to use spacers with a higher viscosity to help prevent the dissolution of salt. The salt should be added to the spacer after the spacer has been hydrated.

Some operational suggestions are to:

• Not reciprocate the casing once the spacer has entered the annulus
• Use modeling software for 100% casing centralization
• Place valves on the mud return lines to stop uncontrolled velocities (freefall) while dropping wiper plugs
• Hold backpressure while displacing to slow annular velocities without exceeding ECDs
• Calculate plug flowrates for mud, spacers and cement based on their low-end rheological properties and minimum calipered hole size.

The success of a primary salt zone cementing operation depends largely on the borehole’s quality. If a large washout occurred during drilling, it becomes increasing difficult to centralize and obtain a good bond across the salt interval. By following the suggestions above, the chances of obtaining good cement job in a difficult environment become more a matter of planning and execution and less a matter of chance.   

LITERATURE CITED

¹ George, D., “Technology that led to mahogany driving global exploration of salt bodies,” Offshore, January 1994, pp. 27–34.
² Moore, D. and R. O. Brooks, “Gulf of Mexico subsalt play is building on its history,” Petroleum Engineer International, December 1995, pp. 26–31.
³ “Major US salt deposits,” Salt Cavern Information Center, http://web.ead.anl.gov/saltcaverns/usdeposit/index.htm.
⁴ “Storage of natural gas,” NaturalGas.Org, http://www.naturalgas.org/naturalgas/storage.asp.
⁵ Barker, J. W. and K. W. Feland, “Drilling long salt sections along the US Gulf Coast,” SPE 24605 presented at the SPE Annual Technical Conference and Exhibition, Washington DC, Oct. 4–7, 1992.
⁶ Muecke, N. B. and N. A. Kiji, “Heated mud systems: The solution to squeezing salt problems,” SPE 25762 presented at the SPE/IADC Drilling Conference, Amsterdam, Feb. 22–25, 1993.
⁷ Heathman, J. and R. Vargo, “Salt vs. non-salt cement slurries: A holistic review,” AADE Paper 06-DF-HO-36 presented at the AADE Drilling Fluids Conference, Houston, April 11–12, 2006.
⁸ Goodwin, K. J. and K. Phipps, “Salt-free cement: An alternative to collapsed casing in plastic salts,” Journal of Petroleum Technology, February 1984, pp. 320–324.
⁹ Martins, A. L., Miranda, C. R., Santos, F. J. P. and A. Bove, “Dynamic simulation of offshore salt zone cementing operations, “ IADC/SPE 74500 presented at IADC/SPE Drilling Conference, Dallas, Feb. 26–28, 2002.
¹⁰ Sweatman, R., Faul, R. F. and C. Ballew, “New solutions for subsalt-well lost circulation and optimized primary cementing,” SPE 56499 presented at ATCE, Dallas, Oct. 6–9, 1999.
¹¹ Van Kleef, R. P. A. R., “Optimized slurry design for salt zone cementations,” SPE/IADC 18620 presented at SPE/IADC Drilling Conference in New Orleans, Feb. 28–March 3, 1989.
¹² Ravi, K. et al.,“Safe and economic gas wells through cement design for life of the well,” SPE 75700 presented at Gas Technology Symposium, Calgary, April 30–May 2, 2002.

.

THE AUTHOR
	Bryan Simmons has been in the industry since 1974. With a BS in petroleum engineering and BA in general studies, Mr. Simmons has served as Field Engineer, District Engineer and Region Engineer for BJ Services. He also has 17 years of field experience as a Cementer and Drillstem Test Tool Operator. His current responsibilities include designing deepwater, HPHT, high salt and conventional cement slurries for the Gulf Coast region and GOM. He is a member of AADE, SPE and the Nicholls State University Petroleum Services Advisory Board, and has served on various other industry-related committees. He is a certified Deepwater Engineer and works in the BJ Services New Orleans office.