Need understanding of loss control beneath salt, osmotic pressure effects
T. J. Griffin Jr., D. J. Oakley, D. A. Stiles
- Increase in the salinity concentration of cement slurry when exposed to test salt block concentrate. [34800 bytes]
There are additional challenges that result from the unique environment of the deepwater Gulf of Mexico. These include very thick salt sections, very deep occurrence of salt, massive lateral extent of the salt, and relatively unknown pressures and temperatures, since this drilling is still in the early exploratory or early development stage.
In the Williston Basin (North Central US), as many as 70% of wells are damaged by salt. This damage is in the form of tight spots, doglegged pipe, completely collapsed pipe, as well as corrosion. Such damage is seen as soon as a few days to as much as eight years later. In the Zechstein salt in Europe, there are similar results with failures occurring as early as during drilling to as late as 12 years later. Problems (tight spots) have also been noted in the Gulf of Suez.
The problem is that the salt behaves as a fluid, or it behaves by elastic deformation. Movement of the salt can actually be in two forms:
- Creep into the wellbore, due to an imbalance of stresses (the stress in the direction of the wellbore is no longer balanced and salt will flow toward and into the wellbore).
- Flow due to geological stresses on a much greater scale (the entire salt body can flow as a mass in one direction).
If the flow is that of a moving body of salt, the forces on the casing are likely to be non-uniform. In either case, such forces are likely to be more significant and complex in a deviated wellbore. The rate of salt flow varies from unnoticeable to closing the hole in just a few days. Hole closure rates up to 2 1/4 in. in 12 hours have been noted in the US Gulf of Mexico at a depth of 17,560-17,870 ft. The closure was stopped by increasing the mud weight from 14.3 lb/gal to 17.3 lb/gal. The rate of flow depends on depth, temperature, mineralogical composition, water content, and the presence of such impurities as clay.
Other factors having an effect include differential stress, confining pressure, grain size, and the presence of oil or other impurities in the salt. One source reported that salt structures distort at widely variable strain rates of 10-8 to 10-16 sec-1. Another proposed an analytical equation to calculate wellbore radius due to creep.
In addition to the direct cause of the problem - apparent mechanical forces on the casing by the salt - a seemingly universally accepted contributing factor to the failures is the quality of the cementation. Most documented failures are attributed to the inadequacy of the cement. This inadequacy may be in the form of retardation of the cement by additives and/or high concentrations of salt, low strength of the cement composition selected, generally poor cementing practices, or poor displacement mechanics.
An additional cementing issue is that of a microannulus or free water channel, either of which can allow flow of unwanted fluids. Such flow could further leach the salt and lead to loss of the well, due to uneconomical water production, damage from salt movement, or casing corrosion.
Changing slurry properties
The properties of cement vary as the concentration of salt in the mix water increases. At low concentrations, the salt acts like an accelerator, shortening the thickening time and increasing compressive strength development.
As the salt concentration approaches saturation, the effects on strength development become very detrimental. Additionally, salt may affect the performance of other additives used to control cement slurry properties. Salt which has been dissolved by the slurry when passing the salt zone will also have an impact on the properties of the cement.
Operators have reported finding incompetent zones in the stratigraphic interval immediately beneath the salt. These are sometimes known as rubble zones or unconsolidated zones. These can lead to massive losses which can have a large impact on the economic success of the well, as well as on the ability to cement through the salt. Over a dozen wells in the Gulf of Mexico have flailed to drill past this section in recent years.
Magnesium brines cause deterioration of the cement by two reported chemical reactions:
Mg2+ + 2H 2O Mg (OH)2 + 2H+
CA (OH)2 + Mg 2+ Mg (OH)2 + Ca2+
Both reactions result in a net increase in volume, resulting in tensile stresses and fracturing of the cement. Additionally, CSH gel (calcium silicate hydrate - the binder) is destabilized due to the reduction in pH, causing a decrease in mechanical strength and an increase in permeability.
Some authors advocate the use of high collapse pressure casing, as much as 1.2 psi/ft and a 1.125 safety factor. Hackney tabulated data on casing failure versus design factors and proposed methods of designing casing. Non-uniform loading of the casing may cause failure at only 21% of the resistance to uniform loading.
Good quality cement is necessary to minimize non-uniform salt loading. Also, such non-uniform loading can be aggravated by eccentric casing. For well-cemented concentric casing strings, "the collapse resistance of cemented casing strings under uniform loads is at least equal to the sum of the individual collapse resistances," reports one researcher.
The quality of the cement and of its placement are critical to effectively protecting the casing from salt. The cement must develop strength quickly enough that movement of the salt does not cause damage prior to its setting. Some advocate the use of fluid loss control. This is especially important if the cement is to be placed across intervals in which there are permeable formations as well as salt.
The effectiveness of mud displacement is also highly critical as the channels resulting from poor displacement can allow flow of unwanted fluids. Additionally, gaps in the cement can aggravate the non-uniformity of forces that is thought to be a major contributor to failure of casing by creeping salts.
The quality of the seal is important to prevent flow of water within the wellbore. Water flows can result in further leaching of the salt and cause non-uniform salt flow and pressure on the casing.
Rike (Rike, 1986) reported that 78% of' failures in the Williston Basin occurred where wellbores were greatly enlarged, even though casing collapse ratings were designed for 1.0-1.5 psi/ft. A gauge hole, proper centralization and a competent cement sheath will eliminate non-uniform, point loading. Mud removal and effective cement placement technology has been improved tremendously since the early days of drilling in the Williston Basin and in other areas from which results are quoted in this paper. There are methods of computing the effectiveness of displacement based on the geometry of the well, in addition to the properties of the fluids.
Hole size is extremely important in achieving a quality cementation. An enlarged hole makes centralization difficult and also makes development of adequate wall shear stress to overcome the gel strength of the mud difficult. Development of wall shear stress is influenced by standoff (gap size) as well as velocity of the fluid and its theological properties. No matter how well the cement slurry is designed, without adequate mud removal, effective cement placement for protection of the casing and zonal isolation is not possible.
A number of methods have been developed to minimize enlargement of the hole while drilling through salt. One is drilling with salt saturated fluid. The concentration of salt to maintain saturation at downhole temperatures is higher than at surface temperatures. Because of this, some method may be required to maintain the desired salt concentration at the surface. There may also be some precipitation which may cause problems due to decreased solubility in cooler riser pipes. Although not frequently applied, two methods that have been successful at maintaining concentrations sufficient for saturation at downhole temperatures are the use of salt precipitation inhibitors and heating of the fluid at the surface. A more common method to minimize hole enlargement is the use of oil based muds. When using such methods to prevent hole enlargement, care must be taken to keep the hole open to prevent pipe sticking due to salt creep. This can be accomplished by use of higher mud weights or by using fresh water pills to dissolve the salt. Care must also be taken to minimize erosional effects, which have been noted by several authors.
The cement properties must be consistent with good slurry design. Special care must be given to certain properties. Thickening times should be kept reasonably short. Long thickening times result in poor strength development, making the wellbore vulnerable to the forces imposed by salt creep. Free water must be kept low to prevent the possibility of a flee water channel. Such a channel can allow unwanted fluids to migrate, including fresh water which could leach the salt.
Fluid loss should be kept low to prevent the development of hole reducing filter cake, or increases in viscosity due to increasing solids concentrations. Either of these can aggravate potential losses to weak zones below. Finally, the viscosity must be optimized to assure minimal particle settling as well as low viscosities for the lowest possible equivalent circulating densities ECD).
It is appropriate to mention here the issue of temperature in wells with massive sections of salt, since temperature has such a large effect on cement properties. The thermal conductivity of salt is about 2-3 times that of other sediments. This means that the flow of heat through the salt results in higher than normal temperatures above the salt, and lower than normal temperatures below the salt. Temperature measurements should be made in the well and not taken from offset well data. Using a two-layer model, one author estimated a difference in temperature of 29 degrees F between a well having a salt sheet 3,280 ft thick and the same well without salt (O'Brien, 1994).
The higher heat flow will have an effect on temperatures in the wellbore and will affect the bottomhole curing temperature (BHCT) as well as the rate of return of the wellbore to bottomhole setting temperature (BHST). In light of these considerations, a robust temperature calculation should be made to determine BHCT for laboratory testing of slurry properties. The temperature calculation should be one that makes the calculations based on heat flow, and not API correlations.
The key set cement properties are the strength and the permeability of the set cement. Although there are very few guidelines for strength which are universally accepted, a key is the early and rapid development of strength. Likewise for the permeability, the key consideration is minimizing permeability to reduce the severity of attack by aggressive brines.
An annular seal is very important. If there is no seal across the salt and adjacent formations, fluids can migrate past the salt. If these fluids are less than saturated, they will leach the salt along the flow path, increasing its size. This can result in accelerating production of undesired fluids and in enlarging the voids around the casing. Such void enlargement can also contribute to non-uniform loading on the casing, which in turn can contribute to casing failure.
Even after setting, the cement can continue to leach salt from the salt formations. This can result in the development of a microannulus at the salt-cement interface. The loss of a seal can also occur if the slurry has free water or if the drilling fluid is not removed effectively and replaced by cement.
Lost circulation control
The potential of lost circulation must be considered in the design of the cement slurries as well as the placement procedures. Slurries must be designed for acceptable hydrostatic pressures as well as minimal friction pressures, which of course contributes to ECD. This means that care must be taken in the selection of fluid loss additives which can cause viscosification of the slurry, and consequently raise the ECD.
The maximum allowable hydrostatic pressure may mean a compromise between reduction of permeability and density. In some cases, more exotic lightweight slurries may be required to achieve the necessary casing protection without the danger of losses. Such lightweight slurries include foamed cement or cement formulated with ceramic microspheres.
- Reduced salt: A number of investigators have advocated the use of reduced salt and salt-free cements for use across salt formations. The rationale for this is that fluid loss is easier to achieve in low salt formulations and that compressive strength development is more rapid.
Unfortunately, a difficulty of this approach is that the introduction of salt to a slurry that was optimized without salt, or an increase in the concentration of the salt in the slurry, especially in the low concentration ranges, will have a large effect on the slurry properties. Such increases can occur as the slurry passes the salt formations.
As much as a 30% change in the thickening time and a 500% change in fluid loss has been reported for an addition of only 10% salt to a fresh water formulation. In addition to the changes in thickening time and fluid loss, dramatic effects on the rheology can be expected. Any dispersed slurry will suffer from the reaction of the salt with the dispersant. Efficiency of dispersants is dramatically affected by salt. Especially in cases where fracturing pressure margins are narrow, this can have a devastating effect on the successful coverage of all the intended intervals uphole.
- Rate of salt dissolution: One author (Goodwin) found that the rate at which salt is dissolved by cement slurry (at room temperature) is relatively slow at plug flow rates Nre = 100 (Nre is the Reynolds number). At laminar flow rates (Nre not defined), he found that above 12% salt BWOW (based on weight of water), the rate at which the salt was dissolved increased as the salt concentration increased. At turbulent rates (Nre 3000), there was severe erosion.
Yearwood found that slurries, mixed with fresh water or with 7.3% salt BWOW and then agitated against a compressed salt block at 140 degrees F, reached a salt concentration of 20% BWOW within 1 hr. After one hour, the concentration increased very slowly beyond 20%.
- High salt slurries: High salt content slurries (generally 18% BWOW) are advocated because of the relative insensitivity of the slurry to increasing salt concentrations. Some reported disadvantages of high salt concentration slurries include: decreased effectiveness of many additives (especially dispersants and fluid loss additives); strong retardation of slurries by concentrations of fluid loss additives necessary to achieve acceptable fluid loss control and by salt insensitive dispersants and thus delayed strength development; difficulty in optimizing theologies due to high viscosities of slurries containing inefficient fluid loss control polymers; difficulty in mixing the slurry; osmotic pressures generated by imbalance of salinities, when placed across low salinity formations.
- Anionic aromatic polymers: Since the work reported above, new slurries have been developed which are based on anionic aromatic polymers (AAP). There are likely other types of polymers that are suitable for use, but in order to illustrate the improvements provided by using such materials to formulate slurries with salt, we will focus on the advantages of formulations based on AAP.
AAP has unique properties when formulated in high salt concentration slurries. These include excellent fluid loss control, low viscosities and friction pressure, and excellent strength development. Low friction pressures mean a reduced risk of breaking down weak formations. A significant advantage of AAP is that slurry formulation to achieve fluid loss control and dispersion is accomplished with a single additive, the AAP. Additionally, this additive is only slightly retarding.
When the salt leaching tests discussed previously were performed, rheologies of the various slurries were measured. There were only minor changes in the rheology of the AAP slurry. The salt-free slurry developed significantly more plastic viscosity, while the slurry originally containing 7.5% salt became unpourable during the test.
- Permeable freshwater zones: There has been discussion of the potential for osmotic pressure between a high salinity slurry and fresh water formations that are covered by the slurry. This discussion is based on work that was begun by Beach and reported in 1982. His work was with slurries that were set and then exposed in an unconfined state to distilled or tap water. It is likely that the results would be much different if he had exposed the specimen to the freshwater in a configuration more like what occurs downhole (with the exposure being through a matrix such as a sandstone core).
- Mitigating magnesium invasion: As discussed previously, the attack by magnesium can result in significant deterioration of the cement. This can best be controlled by the use of low permeability cements. Low permeability implies low water-to-cement ratios (W/C). Low W/C also means high densities or special formulations of lightweight materials such as ceramic spheres. The formulations using AAP are relatively low W/C slurries. The issue of permissible hydrostatic pressure or ECD should be considered in formulating the slurries for use across the salt.
If Mg2+ is not present, the concern is not as great. If it is present, an additional criteria for success is the elimination or prevention of channels through the salt and Mg2+-bearing formations. This means careful attention to the free water of the cement slurry and to the potential for creation of a gap between the salt and cement by leaching, as well as the quality of mud removal.
Tests were conducted with slurries exposed to magnesium brine in 2-in. cube molds. One slurry was saturated with salt with conventional cellulose derivative fluid loss additive while the other contained AAP fluid loss additive. The slurry with the AAP additive had double the strength of the conventional slurry (3,970 psi versus 2,140 psi) after 10 days at 260 degrees F and 8,000 psi curing. Additionally, there was only 17% penetration into the matrix of the AAP slurry, versus 27% for that of the conventional slurry. The brine was 118,000 ppm Mg2+ and 434,000 ppm chloride ions
When analyzing all the literature about cementing in salt carefully, one sees that there are two primary characteristics of the cementation that are necessary to achieve success: good cement placement practices (good mud removal) and rapid strength development.
We believe that a lot of the negative feelings toward high salt concentration slurries have been brought about by the poor strength development and difficulties in formulating an optimum slurry. This was true because of the effects on strength and viscosity of polymers that were available before the development of more effective polymers like AAP. AAP, which is more efficient in salt and is relatively non-retarding, has allowed the design of salt-rich slurries having optimum properties for cementing through massive salts.
The knowledge of mud removal has been improved by the work of Couturier.
- Williston Basin: The use of AAP slurries have resulted in significant improvements in the results in the Williston Basin, as reported by Rae, Whisonant and Morris. Recently, operators were contacted to follow up on wells which were cemented using APP slurries. Of 32 wells on which results were obtained, 31 had no known damage. Only one had a tight spot.
- Permian Basin: Similarly, in the Permian Basin, the use of APP slurries have allowed cementations with reduced problems of lost circulation. This is due to the reduced viscosities and friction pressures of the AAP slurries, compared to slurries formulated with conventional cellulosic fluid loss additives.
- Bluebell-Altamont: AAP slurries have been used to improve the results when cementing across the Wasatch formation. This section is frequently drilled with salt based muds. Cementing results were much improved when using the APP slurries, compared to slurries formulated with cellulosic fluid loss additives. Although the formations drilled contain relatively fresh water, cementing with salt water slurries and formulated with AAP as the fluid loss additive led to good cementing results. Even though annular clearances are small, the low friction pressures of the AAP slurries allowed placement without experiencing lost returns while cementing.
As always, there is additional work to be done. Further development is needed to find methods of controlling losses to the unconsolidated zone beneath the salt. This includes during the drilling and during cementing of that section. A more in-depth investigation into the efforts of osmotic pressure on cement under downhole conditions is needed.
Editor's Note: This paper was presented at the Subsalt '97 conference in Houston. An extensive list of references and acknowledgments, not included here for spatial reasons, can be obtained from the authors (Schlumberger - Houston).
The effect of salt on cement slurry properties.
|System||Plastic Viscosity||Shear Strength||Fluid Loss||Thickening Time||Curing and|
|(cp)||(Ib/100 ft2)||(ml/30 min)||(hr:/min:)||Setting (psi)|
System 2: Class G + 0.5 gps AAP + 30% NACL (BWOW)
Comparison of an anionic aeromatic polymer cement slurry to one with conventional fluid loss additive (bottomhole curing temperature of 160 defrees F and bottomhole setting temperature of 220 degrees F).
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