Drilling Fluids

1. Introduction

The drilling-fluid system—commonly known as the “mud system”—is the single component of the well-construction process that remains in contact with the wellbore throughout the entire drilling operation.
Drilling-fluid systems are designed and formulated to perform efficiently under expected wellbore conditions.
Advances in drilling-fluid technology have made it possible to implement a cost-effective, fit-for-purpose system for each interval in the well-construction process.
The active drilling-fluid system comprises a volume of fluid that is pumped with specially designed mud pumps from the surface pits, through the drill string exiting at the bit, up the annular space in the wellbore, and back to the surface for solids removal and maintenance treatments as needed.
The capacity of the surface system usually is determined by the rig size, and rig selection is determined by the well design. For example, the active drilling-fluid volume on a deepwater well might be several thousand barrels.
Much of that volume is required to fill the long drilling riser that connects the rig floor to the seafloor. By contrast, a shallow well on land might only require a few hundred barrels of fluid to reach its objective.A properly designed and maintained drilling fluid performs several essential functions during well construction.



2. Basic Functions of a drilling fluid

  • Transport cuttings to surface:The fluid should have adequate suspension properties to help ensure that cuttings and commercially added solids such as barite weighing material do not settle during static intervals.

  • prevent well control issues:The column of drilling fluid in the well exerts hydrostatic pressure on the wellbore. Under normal drilling conditions, this pressure should balance or exceed the natural formation pressure to help prevent an influx of gas or other formation fluids. As the formation pressures increase, the density of the drilling fluid is increased to help maintain a safe margin and prevent “kicks” or “blowouts”; however, if the density of the fluid becomes too heavy, the formation can break down.

  • preserve wellbore stability:the wellbore should remain stable under static conditions while casing is run to bottom and cemented. The drilling-fluid program should indicate the density and physicochemical properties most likely to provide the best results for a given interval.

  • minimize formation damage:Drilling operations expose the producing formation to the drilling fluid and any solids and chemicals contained in that fluid. Some invasion of fluid filtrate and/or fine solids into the formation is inevitable; however, this invasion and the potential for damage to the formation can be minimized with careful fluid design that is based on testing performed with cored samples of the formation of interest.

  • cool and lubricate the drill string:The bit and drill string rotate at relatively high revolutions per minute (rev/min) all or part of the time during actual drilling operations. The circulation of drilling fluid through the drill string and up the wellbore annular space helps reduce friction and cool the drill string. The drilling fluid also provides a degree of lubricity to aid the movement of the drill pipe and bottom hole assembly (BHA) through angles that are created intentionally by directional drilling and/or through tight spots that can result from swelling shale.

  • provide information about the wellbore:Because drilling fluid is in constant contact with the wellbore, it reveals substantial information about the formations being drilled and serves as a conduit for much data collected down hole by tools located on the drill string and through wireline-logging operations performed when the drill string is out of the hole.
3. Types of drilling fluids

A drilling fluid can be classified by the nature of its continuous fluid phase. There are three types of drilling fluids:




  1. Water Based Muds

  2. Oil Based Muds

  3. Gas Based Muds

3.1. Water Based Mud

These are fluids where water is the continuous phase. The water may be fresh, brackish or seawater.The following designations are normally used to define the classifications of water baseddrilling fluids:

  1. Non-Inhibited means that the fluid contains no additives to inhibit hole problems.

  2. Inhibited means that the fluid contains inhibiting ions such as chloride, potassium or calcium or a polymer which suppresses the breakdown of the clays by charge association and or encapsulation.

  3. Dispersed means that thinners have been added to scatter chemically the bentonite (clay) and reactive drilled solids to prevent them from building viscosity.

  4. Non-Dispersed means that the clay particles are free to find their own dispersed equilibrium in the water phase.

  5. Non-dispersed-non-inhibited fluids do not contain inhibiting ions such as chloride (Cl-), calcium (Ca2+) or potassium (K+) in the continuous phase and do not utilize chemical thinners or dispersants to affect control of rheological properties.

  6. Non-dispersed- inhibited fluids contain inhibiting ions in the continuous phase, however they do not utilize chemical thinners or dispersants.

  7. Dispersed-non-inhibited fluids do not contain inhibiting ions in the continuous phase, but they do rely on thinners or dispersants such as phosphates, lignosulfonate or lignite to achieve control of the fluids' rheological properties.

  8. Inhibited dispersed contain inhibiting ions such as calcium (Ca2+) or potassium (K+) in the continuous phase and rely on chemical thinners or dispersants to control the fluids rheological properties.

3.2. Oil Based Mud

An oil based mud system is one in which the continuous phase of a drilling fluid is oil. When water is added as the discontinuous phase then it is called an invert emulsion. These fluids are particularly useful in drilling production zones, shales and other water sensitive formations, as clays do not hydrate or swell in oil. They are also useful in drilling high angle/horizontal wells because of their superior lubricating properties and low friction values between the steel and formation which result in reduced torque and drag.

Invert emulsion fluids (IEFs) are more cost-effective than water muds in the following situations:

• Shale stability
• Temperature stability
• Lubricity
• Corrosion resistance
• Stuck pipe prevention
• Contamination
• Production protection
• There are two types of oil based muds:
• Invert Emulsion Oil Muds
• Pseudo Oil Based Mud



3.3. Gas Based Fluids

There are four main types of gas based fluids:

1. Air
2. Mist
3. Foam
4. Aerated Drilling Fluid


These are not common systems as they have limited applications such as the drilling of depleted reservoirs or aquifers where normal mud weights would cause severe loss circulation. In the case of air the maximum depth drillable is currently about 6-8,000 ft because of the capabilities of the available compressors. Water if present in the formation is very detrimental to the use of gas-based muds as their properties tends to break down in the presence of water.

3.4. completion fluids

These are fluids are designed to be non-damaging to the reservoir during the completion of and workover a well. They are usually brines (salty water) which can be made up with up to three different salts depending on the required density. Commonly seawater or sodium chloride is used.

4. Drilling Fluid Testing

1) Field Tests: The drilling-fluids specialist in the field conducts a number of tests to determine the properties of the drilling-fluid system and evaluate treatment needs.

2) Laboratory Tests: Extensive testing of the fluid is performed in the design phase of the fluid, either to achieve desired fluid characteristics or to determine the performance limitations of the fluid.

In the laboratory setting, testing and equipment are available to determine toxicity, fluid rheology, fluid loss, particle plugging, high-angle sag,dynamic high-angle sag, high-temperature fluid aging, cuttings erosion, shale stability, capillary suction, lubricity, return permeability, X-ray diffraction, and particle-size distribution (PSD).

Here are four tests are discussed:



4.1. Fluid Rheology

Fluid rheology is an important parameter of drilling-fluid performance.For critical offshore applications with extreme temperature and pressure requirements, the viscosity profile of the fluid often is measured with a controlled-temperature and -pressure viscometer. Fluids can be tested at temperatures of < 35°F to 500°F, with pressures of up to 20,000 psia. Cold-fluid rheology is important because of the low temperatures that the fluid is exposed to in deepwater risers. High temperatures can be encountered in deep wells or in geothermally heated wells. The fluid can be under tremendous pressure downhole, and its viscosity profile can change accordingly.



4.2. Fluid Loss

If fluid (or filtration) loss is excessive, formation instability, formation damage, or a fractured formation and loss of drilling fluid can occur.Fluid loss also can be measured under dynamic conditions using the Fann 90 viscometer, which incorporates a rotating bob to provide fluid shear in the center of a ceramic-filter core. The fluid is heated and pressurized. Fluid loss is measured radially through the entire core, giving a sophisticated simulation of the drilling fluid circulating in the wellbore.



4.3. Particle Plugging

The particle-plugging test (PPT) often is used to evaluate the ability of plugging particles added to a fluid to mitigate formation damage by stopping or slowing filtrate invasion into a core.



4.4. Toxicity

The environmental and toxicity standards of the region in which the fluid is being used will require testing either of the whole drilling fluid or of its individual components. Toxicity tests generally are used for offshore applications. An approved laboratory can perform the proper testing to ensure compliance of the fluid or its components.



5. Challenges related to drilling fluid

Most operational problems are interrelated making them difficult to solve. Here are examples:

_ loss of circulation into a depleted zone causes a drop in hydrostatic pressure in the wellbore. When the hydrostatic pressure falls too low to hold back formation fluids, the loss incident can be compounded by a kick, the pressure differential created at the loss zone can cause differential sticking for the drillstring.

_ the directional-drilling operation requires an interval of sliding, in which the drillstring is not rotated for a period of time but drilling continues by means of a downhole motor. Sliding allows better directional control, but the lack of pipe rotation can impair hole cleaning. If the drillstring is severely packed off, attempts to circulate drilling fluid might lead to excessive pressure on the wellbore, which in turn can cause the formation below the packoff to break down.



5.1. loss of Circulation

Lost circulation always causes non-productive time that includes the cost of rig time and all the services that support the drilling operation. Loss circulation material (LCM) routinely is carried in the active system on many operations in which probable lost-circulation zones exist.
A variety of LCM is available, and combining several types and particle sizes for treatment purposes is common practice. Conventional—and relatively inexpensive—materials include sized calcium carbonate, paper, cottonseed hulls, nutshells, mica, and cellophane. Because lost circulation always has been one of the most costly issues facing the industry, a focus on healing the loss zone quickly and safely encouraged the development of proprietary materials that conformto the fracture to seal off pores, regardless of changes in annular pressure.
At downhole temperatures, the LCM pill expands rapidly to fill and bridge fractures, allowing drilling and cementing operations to resume quickly, rapid-set LCM products are available that react quickly with the drilling fluid after being spotted across the loss zone and form a dense, flexible plug that fills the fracture and adheres to the wellbore.



Leakoff test (LOT) : Conducting an accurate leakoff test is fundamental to preventing lost circulation. The LOT is performed by closing in the well and pressuring up in the open hole immediately below the last string of casing before drilling ahead in the next interval. On the basis of the point at which the pressure drops off, the test indicates the strength of the wellbore at the casing seat, typically considered one of the weakest points in any interval. However, extending an LOT to the fracture-extension stage can seriously lower the maximum mud weight that may be used to safely drill the interval without lost circulation.



Formation Integrity test (FIT) : To avoid breaking down the formation, many operators perform an FIT at the casing seat to determine whether the wellbore will tolerate the maximum mud weight anticipated while drilling the interval. If the casing seat holds pressure that is equivalent to the prescribed mud density, the test is considered successful and drilling resumes.



5.2. Stuck Pipe

Mechanical causes for stuck pipe include keyseating, packoff from poor hole-cleaning, shale swelling, wellbore collapse, plastic-flowing formation (i.e., salt), and bridging. Preventing stuck pipe can require close monitoring of early warning signs, such as increases in torque and drag, indications of excessive cuttings loading, encountering tight spots while tripping, and experiencing loss of circulation while drilling.Properly managing the lubricity of the drilling fluid and the quality of the filter cake across the permeable formation can help reduce occurrences of stuck pipe.Depending on what the suspected cause of sticking is, it might be necessary to increase the drilling-fluid density (to stabilize a swelling shale) or to decrease it (to protect the depleted zone and avoid differential sticking). A drilling fluid’s friction coefficient is an important factor in its effectiveness in preventing stuck pipe and/or enabling stuck pipe to be worked free. OBFs and SBFs offer the maximum lubricity; inhibitive WBFs can be treated with a lubricant (typically 1 to 5% by volume)and formulated to produce a thin, impermeable filter cake that offers increased protection against sticking. High-performance-polymer WBFs that are designed specifically to serve as alternates to OBFs and SBFs exhibit a high degree of natural lubricity and might not require the addition of a lubricant.



Lubricants for WBFs : Film strength is the main indicator of lubricant performance; generally, the higher the strength, the better the lubricant performance. The alcohol/glycol lubricants also might perform better at low temperatures. Sulfurized oils (e.g., sulfurized olefin) have proved effective under high-pressure conditions and where elevated torque and drag measurements indicate a high risk of stuck pipe. Other lubricant types include glass, plastic, and ceramic beads.



Spotting Fluids : Spotting fluids that are used to free stuck pipe are formulated to first crack the filter cake and then provide sufficient lubricity to allow the pipe to be worked free.



References:

  • Volume II DRILLING ENGINEERING Robert F. Mitchell, Editor.
  • Well Engineering & Construction Hussain Rabia, Editor.