Best Practices and Guidelines for Drilling Through Salt Formation

In drilling operations involving salt formations, several key considerations need to be considered:

1.    Salt Creep:

a.    Salt creep highly depends on the overburden pressure, temperature, moisture content, and salt composition. The creep tendency is more likely and severe at the bottom of the thick salt bed.

b.   Mud weight design is crucial for controlling salt creep. Using proper mud weight based on salt balance load computations and recommended drilling practices should not pose problems with formation mobility.

2.    Fracture resistance in Salt:

a.    Salt formations are considered to have high fracture resistance and hard to fracture.

b.   Companies use different Fracture Initiation Test (FIT) limits in the salt, with potential benefits from in situ stresses.

3.    Drilling Fluids:

a.       Switching to a Synthetic-Based Mud (SBM) after setting the casing into salt offers minimal hole washout, improved Rate of Penetration (ROP), and reduced vibration.

b.       Conventional water-based fluids may lead to salt dissolution, enlarged holes, poor cementation, and potential casing failure, making them less cost-effective.

c.       Salt-saturated mud limits salt dissolution but can still cause some of the above issues, although to a lesser degree.

4.    Directional Work:

a.    Avoiding directional work in salt formations is preferable, if possible, as directional deviation tendencies can be associated with salt flow direction.

b.   Careful control of dogleg severity and bit design is essential to minimize risks associated with the well deviation.

5. Drilling Rate Considerations: Some of the guiding principles for optimizing drilling rate are as follows:

a.    Salt beds are typically light set with unconfined compressive strength (UCS) in the range of 4,000 to 6,000 psi.

b.   The penetration rate while drilling salt formation is usually restricted by the torque capacity of the top drive and the drill string rather than the weight of the bit.

c.    The bit hydraulics and bottom hole cleaning do not play a significant role when drilling through salt formations.

d.   In offshore deep-water drilling, heave compensation could be crucial.

e.    The Water-based mud (WBM) could have a higher penetration rate due to salt dissolving in water. Still, it can also enlarge holes, adversely impacting BHA stabilization and casing cementation. Synthetic fluid Base Mud (SBM) or Oil-Base Mud (OBM) helps achieve a better gauge hole.

f.      Rotary steerable assemblies are the preferred choice for the BHA. Matching the bit design to the BHA is also essential to minimize drill string vibration. Excessive vibration can lead to connection fatigue and electronic and mechanical damage to the MWD/LWD.

g.    Heterogeneous formation layers tend to increase drill string vibration. Since anhydrite streaks can be encountered while drilling salt, utilizing modern tools for monitoring vibration and providing real-time diagnostics, combined with personnel training for managing operating parameters to reduce vibrations appropriately, helps overcome this challenge.

6. Downhole consideration:

a. While drilling through a salt bed, interbedded shales, silts, sand, or tar can be encountered. During the pre-drill phase, every effort should be made to identify interbedded shales, silts, and sandstones to mitigate potential issues.

b. Interbedded shales, silts, and sandstones behave like a “rubble zone.” They may also move under the salt-constricting pressure, leading to pipe sticking.

c. Encountering a sand lens or another permeable formation could raise the possibility of a well kick due to high pore pressure inside the confined lens under overburden stress.

d. The salt tends to move and close around the drill string, risking it getting stuck. Salt mobility depends on various factors like depth, temperature, water content, and type of salt. A salt balance load should be calculated to increase the mud weight required to hold the salt back.

e. In case, the string gets stuck while drilling salt, spotting the freshwater pill around the BHA usually helps release the string.   

7. Kick Considerations:

a. Salt has microporosity, but the possibility of encountering a flow while drilling a thick salt bed cannot be ruled out. It’s not rare to find high-pressure sand lenses embedded within a salt formation or fissures connected to a high-pressure zone that can flow on penetration.

b. Conducting a flow check at the first indication of a drilling break is essential.

c. To handle drilling through the drill break, a watchful strategy of drilling only 3 – 5 ft, followed by picking up the bit above the interval and reaming back to the bottom, can be adopted.

8. Inclusions of Anhydrite, Dolomite, and Limestone:

a. Inclusions of anhydrite, dolomite, and limestone can lead to mud-gelation problems in water-based mud systems.

b. Treatment with bi-carb or lime, as necessary, should be considered to mitigate these issues.

c. It's important to keep drill solids below 4%.

9. Dealing with Tar:

a. It’s not rare to encounter tar while drilling. Tar creates highly troublesome drilling conditions. Running casing becomes difficult due to tar. Tar's high mobility causes sticking problems. Equipment that handles or processes surface mud gets plugged by tar, leading to issues like drilling fluid solid build-up, shale shaker plugging, etc.

b. Tar represents an asphaltene-rich intrusion subjected to significant pressure, nearly equal to the overburden stress. These conditions make it highly mobile, making it difficult to drill through.

c. Occasional encounters with tar typically occur within the first 1,000 feet below the salt and are associated with faulting.

d. Raising mud weight to control mobility does not effectively work with tar. Opting to wait it out and letting sweeps run their course has proven to be a more effective way to deal with tar issues.