Water-base mud

Water-Based Muds. About 85% of all drilling fluids are water-based systems. The types depend on the composition of the water phase (pH, ionic content, etc), viscosity builders (clays or polymers), and rheological control agents (deflocculants or dispersants (qv)). 

Low Solids/Nondispersed. Fresh water, clay, and polymers for viscosity enhancement and filtration control make up low sohd/nondispersed muds. Low soflds muds are maintained using minimal amounts of clay and require removal of all but modest quantities of drill soflds. These are called nondispersed systems because no additives are used to further disperse or deflocculate the viscosity building clays. Most water-based muds are considered dispersed because deflocculating additives are used to control the flow properties. 

The specifications for drilling fluid hematite have been set by the API and are Hsted in Table 2 (24). Hematite is used most frequently in high density oil-based muds to minimise the total volume percent soflds (26). The abrasivity of hematite limits its utiUty in water-based muds. 

Although numerous mud additives aid in obtaining the desired drilling fluid properties, water-based muds have three basic components water, reactive soHds, and inert soHds. The water forming the continuous phase may be fresh water, seawater, or salt water. The reactive soHds are composed of commercial clays, incorporated hydratable clays and shales from drilled formations, and polymeric materials, which may be suspended or dissolved in the water phase. SoHds, such as barite and hematite, are chemically inactive in most mud systems. Oil and synthetic muds contain, in addition, an organic Hquid as the continuous phase plus water as the discontinuous phase. 

Lignite, generally leonardite, and lignite derivatives are appHed in water-based muds as thinners and filtration control agents. Leonardite is an oxidized lignite having a high content of humic acids, which may be described as carboxylated phenoHc polymers (59,60). Litde is known about the chemical stmcture. 

Low molecular weight (1000—5000) polyacrylates and copolymers of acryflc acid and AMPS are used as dispersants for weighted water-base muds (64). These materials, 40—50% of which is the active polymer, are usually provided in a Hquid form. They are particularly useful where high temperatures are encountered or in muds, which derive most of their viscosity from fine drill soHds, and polymers such as xanthan gum and polyacrylamide. Another high temperature polymer, a sulfonated styrene maleic—anhydride copolymer, is provided in powdered form (65,66). AH of these materials are used in relatively low (ca 0.2—0.7 kg/m (0.5—2 lb /bbl)) concentrations in the mud. 

High initial cost and environmental restrictions prevent use of oil and synthetic muds in many cases where shale problems are expected. It is necessary then to treat a water-base mud to minimize the destabilizing effect of the drilling fluid. Salts, polymers, and other organic materials are added to the mud to reduce the water sensitivity of the shale, shale sweUing, and weakening arising from mud contact, or the rate of water uptake by the shale. 

A more recent addition to the Hst of shale protective water-base muds is a system developed around concentrated solutions of methyl glucoside [3149-68-6]. At concentration of 25% by weight and above, methyl glucoside appears to stabilize water-sensitive shales on pat with a typical oil- or synthetic-base mud (122). Eady field trials have been encouraging but much remains to be done before this material is considered a success (123). 

Lignites and lignosulfonates can act as o/w emulsifiers, but generally are added for other purposes. Various anionic surfactants, including alkylarylsulfonates and alkylaryl sulfates and poly(ethylene oxide) derivatives of fatty acids, esters, and others, are used. Very Httle oil is added to water-base muds in use offshore for environmental reasons. A nonionic poly(ethylene oxide) derivative of nonylphenol [9016-45-9] is used in calcium-treated muds (126). 

Other regulations apply in different offshore drilling areas in the United States and around the world. AH have had a profound effect on drilling fluid technology (169,170). Very few instances of water-base muds failing the mysid bioassay test exist in the 1990s. Operators and service companies have eliminated use of the mote toxic additives, reformulated old mud systems, and developed new ones to ensure acceptable environmental performance based on pertinent regulations. 

Entrained gas and air expands under the reduced pressure of the suction stroke, lowering the suction efficiency. Gas in water-base mud may also deteriorate the natural rubber parts used. Gases are usually separated with baffles or by changing mud composition. 

Proper control of the properties of drilling mud is very important for their preparation and maintenance. Although oil-base muds are substantially different from water-base muds, several basic tests (such as specific weight, API funnel viscosity, API filtration, and retort analysis) are run in the same way. The test interpretations, however, are somewhat different. In addition, oil-base muds have several unique properties, such as temperature sensitivity, emulsion stability, aniline point, and oil coating-water wettability that require other tests. Therefore, testing of water and oil-base muds will be considered separately. 

Specific Weight. Mud weight of oil muds is measured with a mud balance. The result obtained has the same significance as in water-base mud. 

Viscosity. The measurement procedure for API funnel viscosity is the same as for water-base muds. Since temperature affects the viscosity, API procedure recommends that the mud temperature should always be recorded along with the viscosity. 

Gel Strength. The gel strength of oil-base muds is measured with a direct indicating viscometer exactly like that of water-base muds. 

Liquids and Solids Content. Oil, water, and solids volume percent is determined by retort analysis as in a water-base mud. More time is required to get a complete distillation of an oil mud than of a water mud. Then the corrected water phase volume, the volume percent of low gravity solids, and the oil-water ratio can be calculated the chart in Figure 4-108 can be used for the calculations [24]. 

Drilling Fluids Composition and Applications Water-Base Mud Systems Bentonite Mud... 

The bentonite muds include most types of freshwater muds. Bentonite is added to water-base muds to increase viscosity and gel strength, and also to improve... 

The oil for an oil-base mud can be diesel oil, kerosene, fuel oil, selected crude oil, or mineral oil. There are several requirements for the oil (1) API gravity = 36° - 37°. (2) flash point = 180°F or above, (3) fire point = 200°F or above, and (4) aniline point = 140°F or above. Emulsifiers are more important in oil-base mud than in water-base mud because contamination on the drilling rig is very likely, and it is very detrimental to oil mud. Thinners, on the other hand, are far more important in water-base mud than in oil-base mud oil is dielectric, so there are no interparticle electric forces to be nullified. 

The advantages of drilling with emulsion muds rather than with water-base muds are (1) higher drilling rate, (2) reduction in drill pipe torque and drag, (3) less bit balling, and (4) reduction in differential sticking. 

Petroleum, whether crude or refined products, need no longer be added to water-based muds. Adequate substitutes exist and are, for most situations, economically viable. Levels of 1% or more of crude oil may be present in drilled rock cuttings, some of which will be in the mud. 

Common salt, or sodium chloride, is also present in dissolved form in drilling fluids. Levels up to 3,000 mg/L chloride and sometimes higher are naturally present in freshwater muds as a consequence of the salinity of subterranean brines in drilled formations. Seawater is the natural source of water for offshore drilling muds. Saturated brine drilling fluids become a necessity when drilling with water-based muds through salt zones to get to oil and gas reservoirs below the salt. 

These generic muds were identified by reviewing the permit requests and selecting the minimum number of mud systems that would cover all those named by the prospective permittees. Eight different mud systems were identified that encompass virtually all water-based muds used on the OCS (Table 4-53) [32A]. Instead of naming a set concentration for each component in each mud system, concentration ranges were specified to allow the operators sufficient flexibility to drill safely. 

The dilution-discard method is the traditional (sometimes the only) way to control the constant increase of colloidal size cuttings in weighted water-base muds. It is effective but also expensive, due to the high cost of barites used to replace the total weighting material in the discard. The daily mud dilutions amount to an average of 5 to 10% of the total mud system. 

SANDS Low pressure. Water or mud blocking. Loss of crude or diesel oil used as completion fluid. Minimum filtration rate water-base muds. Minimum filtration rate water-base emulsions. Miminum filtration rate oU-base emulsions. Oil-base muds. Inhibited muds. Minimum weight muds. Crude oil or diesel oil. Add oil-soluble lost circulation material. 

Typically, water based muds are considered to be incompressible or slightly compressible. For the flow in drill pipe or drill collars, the acceleration component (AP J of the total pressure drop is negligible, and Equation 4-104 can be reduced to... 

Velocity and Attenuation of the Pressure Waves. The velocity and attenuation of the mud pulses or waves have been studied theoretically and experimentally. The velocity depends on the mud weight, mud compressibility, and on the drillpipe characteristics, and varies from 4920 ft/s for a light water-base mud to 3,940 ft/s for a heavy water-base mud. An oil-base mud velocity will vary from 3,940 ft/s for a light mud to 3,280 ft/s for a heavy mud. 

Figure 4-252. Wave amplitude variation as a function of distance in water-base mud and in oil-base mud (a) mud weight, 9 Ib/gal (b) mud weight, 17.9 Ib/galt. (Courtesy Petroleum Erigmeer International [108]. ...

Note that from Table 4-128 the very large volumes that can dissolve in oil-base muds. For the water-base muds, 0.6 to 0.9% of gas will dissolve and not appreciably change the density or compressibility of the mud. It will be difficult to detect these low concentrations with downhole physical measurements. Free gas will be easily detected as shown hereafter. For the oil-base muds we will assume no free gas is present at bottomhole and the mud properties are changed only due to the dissolved gas. The detection will be more difficult than with free gas. 

Table 4-128 shows maximum dissolved gas concentrations in drilling muds at the bottom of the hole. Figure 4-264 shows the variation of the acoustic velocity for two water-base muds and two oil-base muds of 9 and 18 Ib/gal at pressures of 5,000 and 10,000 psi. 

A sharp velocity decrease is seen for the water-base muds. Assuming a threshold detection of 500 ft/s, the alarm could be given for 0.5% of free gas or 1.1 to 1.4% of total gas (dissolved and free). 

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