Addressing Gulf of Mexico subsalt drilling fluid problems
The data shows a significant decrease in erosion when using cloud point glycols in a 20% sodium chloride/EZ-Mud system. Typical subsalt pore pressure, mud weight, and fracture gradient profile. As subsalt drilling and exploration becomes increasingly economically feasible and revenue-generating fields are continually being discovered in the Gulf of Mexico, it becomes imperative to develop successful drilling fluid systems that adequately address problems typically associated with drilling these
Drilling through subsalt sections creates unique fluids challenges
Ward Guillot, Doug Hyatt
Baroid Drilling Fluids
- The data shows a significant decrease in erosion when using cloud point glycols in a 20% sodium chloride/EZ-Mud system.
- Typical subsalt pore pressure, mud weight, and fracture gradient profile.
These problems are often seen when drilling below the salt into an area referred to as the "rafted" zone. It consists of reactive, unconsolidated shale sequences destabilized by the salt intrusion. To be effective a mud system must provide: optimum low equivalent circulating densities with adequate hole cleaning; inhibition in rafted shales; and hole stability.
Subsalt challengesThree major problems consistently encountered when drilling wells in subsalt formations are: loss of well control; lost circulation; and stuck pipe. Historically, various mud types have been used on subsalt wells based on formation type. When drilling above the salt, freshwater, seawater, and enhanced salt systems have been used. These range from traditional defloculated lignosulfonate systems to polymer encapsulating systems. There have been little or no problems associated with drilling above the salt with any of these mud systems, with the exception of light to moderate carbonate contamination which can be easily treated.
For drilling salt and rafted shale, oil mud and saturated salt water-based fluids have been utilized. Major problems encountered when drilling the "rafted" shales below the salt include lost circulation, often resulting in well control problems, and rapid deterioration of the wellbore. These shales are somewhat hydratable and highly dispersible.
When drilling below the rafted shales, systems from freshwater/lignosulfonate to invert emulsion muds have been used. Once the rafted shale is cased off, few problems result in using any of a variety of mud systems.
Mud type selection may depend on several alternatives in casing point selection. Initially, operators tended to set casing above the salt into the last shale section. Since then, several operators have set casing deep into the salt, taking advantage of the increased fracture gradient. This necessitated the use of saturated salt in the interval prior to drilling the rafted shale. More recent wells have penetrated the salt 100-200 feet and set casing at that point. The advantage of this scenario is the use of a less expensive mud system to drill to the salt, spotting saturated salt mud in the salt, setting casing, and then displacing to saturated salt or oil mud.
Based on experience with major operators, our recommendations have been to drill 100 feet into the salt and take advantage of increased fracture gradient. The decision to set casing into the salt versus above salt is made because of problems achieving a good casing seat. Drilling through the rafted zone, which may be anywhere from 100 to 1,500 feet deep, is the critical phase in subsalt exploration.
Pressure profileSeveral operators feel that pore pressure in salt may gradually increase with depth. When rafted shales are encountered below the salt, there may be a sharp increase in pore pressure followed by a pressure regression. Pore pressure should resume its natural trend in the formations below the rafted shale. Because of this, the fracture gradient increases rapidly in the salt, then regresses when entering the "rafted" shales below the salt. The fracture gradient usually returns to normal pore pressure/fracture gradient scale when drilling below the rafted shale. Most problems develop with the combination of a decreasing fracture gradient and an increasing pore pressure, which often results in lost circulation and well control problems .
Extreme caution must be taken when the pore pressure increases and the fracture gradient begins to decrease. Once the fracture gradient is exceeded, it is extremely difficult to stop lost circulation. As the fracture gradient of a formation approaches the pore pressure (i.e., the weight needed to hold the formation open), there is a small window for equivalent circulating density. For example, some experience has shown a 17.5 ppg pore pressure in rafted areas with mud weights of 17.0 ppg.
In addition, once the fracture gradient of the rafted shale is exceeded in a zone with gas or saltwater, the hydrostatic head of the fluid is reduced due to lost circulation. These fluids will then flow in and well control problems will occur. The situation may produce lost circulation in a lower zone with gas intrusion in an upper zone. Therefore, the overall objective is to effectively drill the rafted section with as few problems as possible to set pipe before entering the production zones.
To complicate matters, these rafted shales are somewhat hydratable and highly dispersible. Extensive washout problems, even with oil muds, can occur resulting in hole cleaning problems. While this pressure profile is an uncontrollable natural occurrence, mud systems can be designed to inhibit the hydration and dispersion of these rafted shales.
Cloud point characteristicsThe use of glycols as drilling fluid additives has been common practice for several years and has seen promise when used for problems encountered during subsalt drilling. However, the exact mechanisms and benefits of glycols have been debated within the industry. Recent work has focused on the use of cloud point glycols as shale inhibitors. Baroid has met the demands for performance and environmental requirements with a range of highly inhibitive glycol-based drilling fluid additives. The additives for cloud point glycol-enhanced mud (GEM) offer the following advantages: enhanced shale inhibition, improved filter cake quality, reduced fluid loss, and improved lubricity.
Dispersibility of shales can be evaluated using hot rolling erosion data. Figure 3 shows a significant decrease in erosion when using cloud point glycols. GEM improves the inhibition and stability of clays and shales. Field data has shown that GEM can produce a much improved, near-gauge hole as compared to the same mud systems in offset wells drilled without GEM. Lab data using reconstituted "rafted" shales shows significant improvement in hot rolling erosion testing when using cloud point glycols. This data also indicates that cuttings will be transported to the surface in the GEM system without dispersion and hydration and can be more easily removed by the solids control equipment.
Laboratory testing has concluded that upon reaching cloud point temperature, shale inhibition is significantly improved. Cloud point behavior describes the phenomenon where certain GEM water-soluble additives become insoluble and come out of solution when there are changes in temperature, GEM concentration or salinity. This cloud point temperature can also be adjusted using various glycols or combinations of these glycols. Ideally, the flowline temperature will be low enough to allow the glycol to become soluble on surface while downhole conditions are above the cloud point temperature, rendering the glycol insoluble.
API and HTHP fluid loss have been improved with additions of GEM both in laboratory and field muds. Tests also show a reduction in the Cake Deposit Index (dynamic filtration) when are added to a mud system. This improvement in filter cake quality and the lower fluid loss will significantly reduce the chances of differential sticking. This same mechanism of improved filter cake quality contributes to increased lubricity.
Typical fluids applicationWhen a seawater dispersed mud system is used to drill into the salt, particular attention must be paid to alkalinity (carbonate contamination). After the salt is penetrated, this system must be treated for salt contamination and a saturated salt pill should be spotted prior to tripping out of the hole. This minimizes leaching in the salt formation. Casing will be run at this time to take full advantage of the increased fracture gradient in the salt.
After the formation is tested at the casing shoe, the seawater dispersed mud is displaced with a saturated salt/GEM system. While cloud point glycol additives may not be necessary to drill the salt, it may be advisable to have the mud conditioned to drill the rafted shales below. Mud weight prediction necessary to drill below the salt is critical at this point. Equivalent circulating densities should be controlled by maintaining minimal rheological properties. However, adequate viscosity must be maintained to ensure hole cleaning. In order to avoid excessive annular loading, the rafted shale should be control drilled.
Salt saturation should be maintained using a salt inhibitor to ensure a gauged hole through the salt and increased inhibition through the rafted shale. Ideally, the rafted shale can be drilled without incident and casing set through the interval; however, a contingency plan for lost circulation should be in place. The lost circulation contingency plan should include gunk squeezes utilizing synthetic/bentonite/cement. This type of squeeze has been successful in this application.
When available, cores of the rafted shales drilled on offset wells can be used to fine tune the proposed mud system, making every effort to avoid these drilling problems.
While subsalt formations can present significant drilling challenges, these formations can be successfully drilled utilizing cloud point glycol enhanced mud systems to inhibit shale, improve filter cake quality and reduce fluid loss through the rafted zones.
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