Water Base Muds

A water-base drilling fluid is one that has water as its continuous or liquid phase. The types of drilling fluids are briefly described in the following sections.

Freshwater muds are generally lightly treated or untreated muds having a liquid phase of water, containing small concentrations of salt, and having a pH ranging from 8.0 to 10.5. Freshwater muds include the following types.

Spud Muds These muds are prepared with available water and appropriate concentrations of bentonite and/or premium commercial clays. They are generally untreated chemically, although lime, cement, or caustic soda is occasionally added to increase viscosity and give the mud a fluff to seal possible lost return zones in unconsolidated upper hole surface formations. Spud muds are used for drilling the surface hole. Their tolerance for drilled solids and contaminants is very limited.

Natural Mud Natural or native muds use native drilled solids incorporated into the mud for viscosity, weight, and fluid loss control. They are often supplemented with bentonite for added stability and water loss control. Surfactants can be used to aid in controlling mud weight and solids buildup. Natural muds are generally used in top hole drilling to mud-up or to conversion depth. They have a low tolerance for solids and contamination.

Saltwater Muds Muds ordinarily are classified as saltwater muds when they contain more than 10,000 mg/L of chloride. They may be further classified according to the amount of salt present and/or the source of makeup water (see Table 1.3):

Amount of chloride in mg/L

  1. Saturated salt muds (315,000 ppm as sodium chloride)
  2. Salt muds (over 10,000 mg/L chloride but not saturated)

Source of make-up water

  1. Brackish water
  2. Sea Water

Saltwater muds may be purposely prepared, or they may result from the use of salty makeup water, from drilling into salt domes or stringers, or when saltwater flows are encountered. Saltwater muds include the following types.

TABLE 1.3 Seawater Composition

Equivalent Parts


Parts per Million

per Million



















Carbon dioxide



Other constituents



Seawater or Brackish Water Muds These muds are prepared with available makeup water, both commercial and formation clay solids, caustic soda, and lignite and/or a lignosulfonate. CMC is usually used for fluid loss control, although concentration of lignites and lignosulfonates are also often used for this purpose. Viscosity and gel strength are controlled with caustic soda, lignosulfonate, and/or lignites. Soda ash is frequently used to lower the calcium concentration. CMC or lignosulfonates are used for water loss control, and pH is controlled between 8.5 to 11.0 with caustic soda. Seawater muds and brackish or hard water muds are used primarily because of the convenience of makeup water, usually open sea or bays. The degree of inhibitive properties varies with the salt and calcium concentration in the formulated fluid.

Saturated Salt Muds Saturated salt water (natural or prepared) is used as makeup water in these fluids. Prehydrated bentonite (hydrated in freshwater) is added to give viscosity, and starch is commonly used to control fluid loss. Caustic soda is added to adjust the pH, and lignosulfonates are used for gel strength control. Occasionally, soda ash may be used to lower filtrate calcium and adjust the pH. Saturated salt muds are used to drill massive salt sections (composed mainly of NaCl) to prevent washouts and as a work-over or completion fluid. Freshwater bentonite suspensions are converted by adding NaCl to reach saturation. Conversion is carried out by diluting the freshwater mud to reduce the viscosity "hump" seen in breakovers. Saturated salt muds usually are used at mud weights below 14.0 lb/gal.

Composition of NaCl mud

  • Brine NaCl
  • Density — salt, barite, calcium carbonate or hematite
  • Viscosity — CMC HV, Prehydrated bentonite, XC-polymer (xanthan gum)
  • Rheology — lignosulfonate
  • Fluid Loss — CMC LV or PAC (polyanionic cellulose)
  • pH - Pf (alkalinity) — caustic potash or caustic soda

Chemically Treated Mud (No Calcium Compounds) This type of mud is made up of a natural mud that has been conditioned with bentonite and treated with caustic soda and lignite or lignosulfonate (organic thinner). No inhibiting ions are found in this type of fluid.

Lignite/Lignosulfonate Mud This fluid is prepared from freshwater and conditioned with bentonite. Lignosulfonate is added as a thinner and lignite for filtration control and increased temperature stability. CMC or PAC may be used for additional filtration control when the bottom-hole temperature does not exceed 121°C (250°F). This type of mud is applied at all mud weights and provides a relatively low pH system (pH values for calcium lignosulfonates will be 10.0-11.0). This type of fluid is stable at reasonably high temperatures (325°F) and has good resistance to contamination.

Calcium Treated Muds Calcium-treated fluids are prepared from any low or high pH mud by the addition of appropriate amounts of lime or gypsum, caustic soda, and thinner (lignite or lignosulfonate). Calcium-treated muds include lime and gypsum muds.

Lime Muds Lime muds include low- and high-lime muds. They are prepared from available muds by adding calcium lignosulfonate, lignite, caustic soda or KOH, lime, and a filtration-control material, PAC or starch. Caustic soda is used to maintain the filtrate alkalinity (Pf values) and lime to control the mud alkalinity (Pm values) and excess lime. Lime muds offer resistance to salt, cement, or anhydrite contamination even at high mud weights.

Gypsum Mud Commonly called "gyp muds," they are prepared from freshwater and conditioned with bentonite or from available gel and water mud. Caustic soda is added for pH control. Gypsum, lignosulfonate, and additional caustic soda are added simultaneously to the mud. CMC may be added for filtration control. This fluid is used for drilling in mildly reactive shale or where gypsum or anhydrite must be drilled. It resists contamination from cement or salt. Use is limited by the temperature stability of the filtration control materials, CMC (250°F ±).

1.3.9 Special Muds

In addition to the most common mud systems discussed previously, there are other muds that do not fall neatly into one category or another in the classification scheme.

Low-Density Fluids and Gaseous Drilling Mud (Air-Gas Drilling Fluids) The basic gaseous drilling fluids and their characteristics are presented in Table 1.4.

This system involves injecting air or gas downhole at the rates sufficient to attain annular velocity of 2,000 to 3,000 ft/min. Hard formations that are relatively free from water are most desirable for drilling with air-gas drilling fluids. Small quantities of water usually can be dried up or sealed off by various techniques.

Air-gas drilling usually increases drilling rate by three or four times over that when drilling with mud, as well as one-half to one-fourth the number of bits are required. In some areas, drilling with air is the only solution;

1.3 TESTING OF DRILLING SYSTEMS TABLE 1.4 Gaseous Drilling Mud Systems

Type of Mud Density, ppg PH Temp. Limit °F Application Characteristics


High-energy system. Fastest drilling rate in dry, hard formations. Limited by water influx and hole size.


High-energy system. Fast penetration rates. Can handle water intrusions. Stabilizes unstable holes (mud misting).


Very-low-energy system. Good penetration rates. Excellent cleaning ability regardless of hole size. Tolerates large water influx.

these are (1) severe lost circulation, (2) sensitive producing formation that can be blocked by drilling fluid (skin effect), and (3) hard formations near the surface that require the use of an air hammer to drill.

There are two major limitations with using air as a drilling fluid: large volumes of free water and size of the hole. Large water flows generally necessitate converting to another type of drilling fluid (mist or foam). Size of the hole determines a volume of air required for good cleaning. Lift ability of air depends annular velocity entirely (no viscosity or gel strength). Therefore, large holes require an enormous volume of air, which is not economical.

Mist Drilling Fluids Misting involves the injection of air and mud or water and foam-making material. In the case of "water mist," only enough water and foam is injected into the air stream to clear the hole of produced fluids and cuttings. This unthickened water can cause problems due to the wetting of the exposed formation, which can result in sloughing and caving of water-sensitive shale into the wellbore. Mud misting, on the other hand, coats the walls of the hole with a thin film and has a stabilizing effect on water-sensitive formations. A mud slurry that has proved adequate for most purposes consists of 10ppb of bentonite, 1 ppb of soda ash, and less than 0.5 ppb of foam-stabilizing polymer such as high-viscosity CMC. If additional foam stability is needed, additional foamer is used.

Nondispersed (Low-Solids) Muds The term low-solids mud covers a wide variety of mud types, including clear water (fresh, salt, or brine), oil-in-water emulsions, and polymer orbiopolymer fluids (muds with polymer and no other additives).

Extended Bentonite Muds Low-solids nondispersed mud is generally prepared from freshwater with little or no drilled solids and ben-tonite, along with a dual-action polymer for extending the bentonite and flocculating drilled solids. This type of mud is designed for low-solids content and to have low viscosity at the bit for high drilling rates. The polymers used greatly increases the viscosity contributed by the bentonite and serve as flocculants for native clay solids, making them easier to remove by solids-control equipment. These polymers or bentonite extenders permit the desired viscosity to be maintained with about half of the amount of bentonite normally required. No deflocculant is used, so a flocculated system is maintained. The flocculation and lower solids content permit the mud to have a relatively low viscosity at the bit and at the bottom of the hole, where shear rates are high, and a relatively high viscosity at the lower shear rates in the annulus for good hole cleaning. One problem with this type of fluid is that filtration rates are fairly high, because the solids are flocculated and their quantity is low. This means that they do not pack tightly in the filter cake. Sodium polyacrylates or small amounts of CMC may be added for filtration control.

The temperature limitation of extended bentonite fluids is 200-275F0. Otherbenefits include improved hydraulics and less wear on bits and pump parts.

Inhibitive Salt/Polymer Muds An inhibitive mud is one that does not appreciably alter a formation once it has been cut by the bit. The term covers a large number of mud systems, among them saltwater muds with more than 10,000 mg/L of sodium chloride, calcium-treated muds (lime and gyp), and surfactant-treated muds. Under the category of inhibiting salt/polymer muds, however, we are speaking specifically about muds containing inhibitive salts such as KCl, NaCl, or diammonium phosphate along with complex, high-molecular-weight polymers. In these muds, pre-hydrated bentonite and polymer are added for viscosity and gel strength, polyanionic cellulose (PAC) or CMC are added for fluid loss control, and corrosion inhibitors and oxygen scavengers often are used to protect tubular goods. These muds are used for drilling and protecting water-sensitive formations and are good for minimizing formation damage due to filtrate invasion when the formation contains hydratable clay solids. Good hole cleaning and shear thinning are characteristics of these fluids. High-solids concentrations cannot be tolerated, however, making good solids control very important. Temperature limitations of 200-2500F are also characteristic. Among the muds of this type is KCl/lime mud. This mud system uses pre-hydrated bentonite or KCl for inhibition, lignosulfonate and/or lignite as a thinner, KOH (caustic potash) or caustic soda for alkalinity, lime for alkalinity and inhibition, and polymers such as CMC or PAC for filtration control.

Surfactant Muds Surfactant muds were developed primarily to replace calcium-treated muds when high temperature becomes a problem. The term surfactant means surface-acting agent, or a material that is capable of acting on the surface of a material. In drilling muds, surfactants are additives that function by altering the surface properties of the liquid and solid phases of the mud or by imparting certain wetting characteristics to the mud. The composition of the surfactant mud system tends to retard hydration or dispersion of formation clays and shales. The pH of these muds is kept from 8.5 to 10.0 to give a more stable mud at higher temperatures.

The surfactant mud usually encountered is a lignite surfactant mud system. This mud is made up from freshwater using bentonite, lignite, and the surfactant. Small amounts of defoamer may be required with the addition of the lignite. The pH of this mud is maintained within closely fixed limited (8.5 -10.0) for maximum solubility of the thinner (lignite). Tolerance to salt, gyp, and cement contamination is limited. To retain satisfactory flow properties at high temperatures, the clay content of the mud must be kept low (1-1.6 CEC capacity) through the use of dilution and solids-control equipment. The combination of lignite with surfactant in this mud enables its use at extremely high bottom-hole temperatures. This is due to the temperature stability of lignite and the effect of the surfactant in providing viscosity control and minimizing gel strength development at higher temperatures.

High-Temperature Polymer Muds Development of a high-temperature polymer system evolved from a need for a mud system with low solids and nondispersive performance at higher temperatures. System capabilities:

  • Good high-temperature stability
  • Good contaminant tolerance
  • Can formulate temperature stable nondispersed polymer mud system
  • Can be used in wide variety of systems for good shale stability
  • Minimum dispersion of cuttings and clays
  • Flexibility of general application

Application of the high-temperature polymer system primarily consists of five products: (1) polymeric deflocculant, (2) acrylamide copolymer, (3) bentonite, (4) caustic soda or potassium hydroxide, and (5) oxygen scavenger. Barite, calcium carbonate, or hematite is then used as a weighting agent.

The polymeric deflocculant is a low-molecular-weight, modified poly-acrylate deflocculant used to reduce rheological properties of the system. If differs from lignosulfonates in that it does not require caustic soda or an alkaline environment to perform. Limited amounts of the polymer may be used in low-mud-weight systems, but larger additions will be needed at higher mud weights and when adding barite to increase the fluid density.

The backbone of the system is an acrylamide copolymer used to control fluid loss. In freshwater systems, 1 to 2 lb/bb will be the range required to control the API fluid loss. In seawater systems, the concentration will range from 4 to 5 lb/bbl. HPHT fluid loss can also be controlled with the polymer. It is not affected by salinity or moderate levels of calcium. At higher concentrations of contaminants, some increase in viscosity will result.

Caustic soda and/or potassium hydroxide are alkaline agents used to control the pH of the system. Either is used to maintain the system pH between 8.3 and 9.0.

Oxygen scavengers serve two purposes in this system. First, because of the low pH characteristic of the system, it should be added to protect the drill pipe. (Run corrosion rings in the drill pipe to determine treatment rates for the corrosion that may be occurring.) Second, as the temperature of the mud exceeds 300°F, any oxygen present will react with the polymers and reduce their efficiency. Additional treatment will be required to replace affected or degraded polymers.

New-Generation Water-Based Chemistry Several companies have developed water-base fluids that provide the inhibition formerly seen only when using oil-base fluids. Novel chemistry such as sodium silicates, membrane-efficient water-base muds, and highly inhibiting encapsulating polymers make these new systems unique and high in performance. Product development in the area of highly inhibitive polymers will no doubt result in the total replacement of invert emulsions. The need to provide more environmentally acceptable products drive the research and development of many drilling fluids by vendors around the world.

Oil-Base Mud Systems and Nonaqueous Fluids (NAF) Oil-base muds are composed of oil as the continuous phase, water as the dispersed phase, emulsifiers, wetting agents, and gellants. Other chemicals are used for oil-base mud treatment, such as degellants, filtrate reducers, and weighting agents.

The oil for an oil-base mud can be diesel oil, kerosene, fuel oil, selected crude oil, mineral oil, vegetable esters, linear paraffins, olefins, or blends of various oils. There are several desired performance requirements for any oil:

  • API gravity = 36° -37°
  • Flash point = 180°F or above
  • Fire point = 200°F or above
  • Aniline point = 140°F or above

Emulsifiers are very important in oil-base mud because water contamination on the drilling rig is very likely and can be detrimental to oil mud. Thinners, on the other hand, are far more important in waterbase mud than in oil-base mud; oil is dielectric, so there are no interparticle electric forces to be nullified.

The water phase of oil-base mud can be freshwater or various solutions of calcium chloride (CaCl2), sodium chloride (NaCl), or formates. The concentration and composition of the water phase in oil-base mud determines its ability to solve the hydratable shale problem.

The external phase of oil-base mud is oil and does not allow the water to contact the formation; the shales are thereby prevented from becoming wet with water and dispersing into the mud or caving into the hole.

The stability of an emulsion mud is an important factor that has to be closely monitored while drilling. Poor stability results in coalescence of the dispersed phase, and the emulsion will separate into two distinct layers. Presence of any water in the HPHT filtrate is an indication of emulsion instability.

The advantages of drilling with emulsion muds rather than with waterbase muds are

  • High penetration rates
  • Reduction in drill pipe torque and drag
  • Less bit balling
  • Reduction in differential sticking

Oil-base muds are generally expensive and should be used when conditions justify their application. As in any situation, a cost-benefit analysis should be done to ensure that the proper mud system is selected. Oil-based fluids are well suited for the following applications:

  • Drilling troublesome shales that swell (hydrate) and disperse (slough)
  • Drilling deep, high-temperature holes in which water-base muds solidify
  • Drilling water-soluble formations such as salt, anhydride, camallite, and potash zones
  • Drilling the producing zones

For additional applications, oil muds can be used

  • As a completion and workover fluid
  • As a spotting fluid to relieve stuck pipe
  • As a packer fluid or a casing pack fluid

Drilling in younger formations such as "gumbo," a controlled salinity invert fluid is ideally suited. Gumbo, or plastic, flowing shale encountered in offshore Gulf of Mexico, the Oregon coast, Wyoming, West Africa, Venezuela, the Middle East, Western Asia, and the Sahara desert, benefits from a properly designed salinity program. Drilling gumbo with water-base mud shale disperses into the mud rapidly, which reduces the drilling rate and causes massive dilution of the mud system to be required. In some cases, the

ROP must be controlled to prevent plugging of the flowline with hydrated "gumbo balls." Solids problems also are encountered with water-based fluid drilling gumbo such as bit balling, collar balling, stuck pipe, and shaker screens plugging.

Properly designed water-phase salinity invert fluids will pull water from the shale (through osmosis), which hardens the shale and stabilizes it for long-term integrity.

Generally, oil-base mud is to delivered to the rig mixed to the desired specifications. In some cases, the oil-base mud can be mixed on location, but this process can cost expensive rig time. In the latter case, the most important principles are (1) to ensure that ample energy in the form of shear is applied to the fluid and (2) to strictly follow a prescribed order of mixing. The following mixing procedure is usually recommended:

  1. Pump the required amount of oil into the tank.
  2. Add the calculated amounts of emulsifiers and wetting agent. Stir, agitate, and shear these components until adequate dispersion is obtained.
  3. Mix in all of the water or the CaCl2-water solution that has been pre-mixed in the other mud tank. This requires shear energy. Add water slowly through the submerged guns; operation of a gun nozzle at 500 psi is considered satisfactory. After emulsifying all the water into the mud, the system should have a smooth, glossy, and shiny appearance. On close examination, there should be no visible droplets of water.
  4. Add all the other oil-base mud products specified.
  5. Add the weighting material last; make sure that there are no water additions while mixing in the weighting material (the barite could become water wet and be removed by the shale shakers).

When using an oil-base mud, certain rig equipment should be provided to control drilled solids in the mud and to reduce the loss of mud at the surfaces:

  • Kelly valve—a valve installed between the Kelly and the drill pipe will save about one barrel per connection.
  • Mud box—to prevent loss of mud while pulling a wet string on trips and connections; it should have a drain to the bell nipple and flow line.
  • Wiper rubber—to keep the surface of the pipe dry and save mud.

Oil-base mud maintenance involves close monitoring of the mud properties, the mud temperature, and the chemical treatment (in which the order of additions must be strictly followed). The following general guidelines should be considered:

A. The mud weight of an oil mud can be controlled from 7lb/gal (aerated) to 22lb/gal. A mud weight up to 10.5lb/gal can be achieved with sodium chloride or with calcium chloride. For densities above

TABLE 1.5 Estimated Requirements for Oil Mud Properties

Mud Weight,

Plastic Viscosity,

Yield Point,





lbs/sq ft2



























Above 600

  1. 5 lb/gal, barite, hematite, or ground limestone can be used. Calcium carbonate can be used to weight the mud up to 14 lb/gal; it is used when an acid-soluble solids fraction is desired, such as in drill-in fluids or in completion/workover fluids. Iron carbonate may be used to obtain weights up to 19.0 lb/gal when acid solubility is necessary (Table 1.5).
  2. Mud rheology of oil-base mud is strongly affected by temperature. API procedure recommends that the mud temperature be reported along with the funnel viscosity. The general rule for maintenance of the rheo-logical properties of oil-base muds is that the API funnel viscosity, the plastic viscosity, and the yield point should be maintained in a range similar to that of comparable-weight water muds. Excessive mud viscosity can be reduced by dilution with a base oil or with specialized thinners. Insufficient viscosity can be corrected by adding water (pilot testing required) or by treatment with a gallant, usually an organophilic clay or surfactant.
  3. Low-gravity solids contents of oil-base muds should be kept at less than 6%v/v. Although oil muds are more tolerant for solids contamination, care must be taken to ensure that solids loading does not exceed the recommended guidelines. A daily log of solids content enables the engineer to quickly determine a solids level at which the mud system performs properly.
  4. Water-wet solids is a very serious problem; in severe cases, uncontrollable barite setting may result. If there are any positive signs of water-wet solids, a wetting agent should be added immediately. Tests for water-wet solids should be run daily.
  5. Temperature stability and emulsion stability depend on the proper alkalinity maintenance and emulsifier concentration. If the concentration of lime is too low, the solubility of the emulsifier changes, and the emulsion loses its stability. Lime maintenance has to be established and controlled by alkalinity testing. The recommended range of lime content for oil-base muds is 0.1 to 4 lb/bbl, depending on base oil being used. Some of the newer ester-base muds have a low tolerance for hydroxyl ions; in this case, lime additions should be closely controlled.
  6. CaCl2 content should be checked daily to ensure the desired levels of inhibition are maintained.
  7. The oil-to-water ratio influences funnel viscosity, plastic viscosity, and HTHP filtration of the oil-base mud. Retort analysis is used to detect any change in the oil-water ratio, because changes to the oil-water ration can indicate an intrusion of water.
  8. Electrical Stability is a measure of how well the water is emulsified in the continuous oil phase. Because many factors affect the electrical stability of oil-base muds, the test does not necessarily indicate that a particular oil-base muds, the test does not necessarily indicate that a particular oil-base mud is in good or in poor condition. For this reason, values are relative to the system for which they are being recorded. Stability measurement should be made routinely and the values recorded and plotted so that trends may be noted. Any change in electrical stability indicates a change in the system.
  9. HTHP filtration should exhibit a low filtrate volume (< 6 ml). The filtrate should be water free; water in the filtrate indicates a poor emulsion, probably caused by water wetting of solids.

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  • Mary
    How to raise water ph using calcium lignosulfonate?
    3 years ago
  • pontus
    What is the effect of the increased salinity of salt saturated kcl polymer mud?
    2 years ago
  • william santana
    Why caustic soda is added in drilling fluid?
    2 years ago
  • mika
    Why is lignosulfonate mud more preferable in cameroon than other mud types?
    2 years ago
  • felicita derose
    What are the disadvantages encountered when the pH of a mud is basic?
    2 years ago
  • saimi
    Why is prehydrated bentonite used for high salinity muds?
    1 year ago
  • ute
    How to raise viscosity water based drilling fluid?
    12 months ago
  • Sara
    How to reduce water base mud rheology?
    11 months ago
    What is maximum weight of water base mud in oilfield?
    6 months ago
  • Debora Schiavone
    What is the use of water based mud in rigs?
    5 months ago
  • Dominik
    How adding barite is sensitive to mixing ?
    2 months ago
  • charles
    How to prepare water base mud?
    1 month ago

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