Friday, 31 July 2020


Simple Guide To Oil Based Mud. 

oil based mud overview definition properties


  • Describe the chemical formulation of oilbased muds.
  • Describe the ways in which the: wettability; activity; viscosity and filtration of oil based mud can be measured..

Introduction To Oil Based Mud

An oil based mud is one in which the base fluid from which the mud is made up is oil. Since the 1930’s it has been recognized that better productivity is achieved from reservoirs when oil based muds rather than Water Based Mud are used to drill through the reservoir. This is largely because the oil does not cause the clays in the reservoir to swell or cause changes in wettability of the formations. Crude oil was first used to drill through the pay zone, but it suffered from several disadvantages (low gel strength, limited viscosity, safety hazard due to low flash point).

Modern oil based muds use low-toxicity base oils and a variety of chemical additives to build good mud properties. The use of oil in the drilling mud does have several disadvantages:

  • Higher initial cost
  • More stringent pollution controls required
  • Reduced effectiveness of some logging tools (resistivity logs) 
  • Detection of Kicks more difficult due to gas solubility in base oil 
However for some applications oil based muds are very cost effective. These include:
  • To drill and core pay zones 
  • To drill troublesome formations (e.g. shale, salt) 
  • To add lubricity in directional drilling (preventing Stuck Pipe
  • To reduce corrosion

As a completion fluid (during perforating and workovers), there are three types of oil based muds in common use:
  • Full oil (water content < 5%)
  • Invert oil emulsions (water content 5 - 50%)
  • Synthetic or Pseudo oil based mud
In brief, two types of oil based muds are commonly used. An oil mud has less than 5% water. An invert emulsion has a water concentration greater than 5%. The oil based muds are generally used for specific purposes, such as maintaining hole stability in hydratable formations or drilling hydrogen sulfide-bearing zones. While drilling hydratable formations, it is important that the salinity level of an oil based mud be maintained at levels greater than the salinity of the formation being drilled. Mud contamination from hydrogen sulfideor carbon dioxide gas can be controlled with excess lime in an oil based system.

The History Of Oil Based Mud

Historically, diesel has been the primary oil source for the continuous phase of oil based muds. Pollution restrictions, especially in offshore environments, have necessitated the use of a mineral oil phase that is within environmental safety levels. Refineries are now supplying highly processed paraffin based oils that meet these environmental safety standards. Except for a few physical characteristics, these new oils are handled and mixed in a manner similar to diesel oil

The Initiation Of Oil Based Mud   

The first oil based mud was crude oil, and was used to complete shallow, low pressure zones. Although there is no record of its first usage, it probably occurred soon after the advent of rotary drilling. The first patent application for an oil based mud was issued in 1923, but this mud was not a commercial success. Oil Based  Muds Company (now Hughes Drilling Muds) was formed by George Miller to manufacture, market, and service the first commercial oil based mud, Black Magic.

Oil Based Mud & Richfield Oil Company

On May 1, 1942, Richfield Oil Company (now ARCO) used Black Magic as a completion mud. Black Magic at that time was composed of air blown asphalt dispersed in a diesel oil which contained naturally occurring naphthenic acid, quick lime, and 5% by volume water. The uses of Black Magic in these early years were as completion fluids for low pressure and/or low permeability sands, coring fluids, and to free Stuck Pipe.

The Black Magic Did Good

This original system performed well when applied properly. However, it had some obvious drawbacks. Asphalt was the primary viscosifier and fluid loss control additive. It did a good job of both but contributed to very high apparent and plastic viscosities and consequently was detrimental to drilling rates when compared to a Water Based Mud of the same density. It was also much more expensive per unit volume than water based mud.

Why They Called It Invert Emulsion Mud

Because it did perform many functions well, the industry then set about to improve on it. From this work came the development of what are called the Inverts or Invert Emulsion Muds. Invert emulsion means that water is emulsified in oil (water-in-oil emulsion). In the earlier years (1940’s), one of the most popular Water Based Mud run was oil in-water. These muds were called oil emulsion systems. Therefore, during the development of invert emulsion systems, the term ”inverts” or invert emulsion was used to differentiate the oil system containing some oil.

The development Of Oil Based Mud Additives

The control of the water base muds is made possible because of the wide variety of additives available for performing specific functions. At this time in history, development of oil mud additives and the technology of oil muds were pointed in the same direction. The first step dealt with the amount of water emulsified. Inverts were developed to contain and tolerate a much greater water volume than true oil muds. Rheology could then be controlled by altering oil/water ratios. This allowed the system to have adequate weight material suspension and filtration control with lower viscosity and gels. Water contamination became a less acute problem with   inverts. Oil/water ratios ranged from 55/45 to 70/30

The High Cost Of Oil Mud Preparation

The initial preparation of many oil muds tended to be time consuming and expensive because additives such as asphalt did not blend readily in crude or diesel oils but required heat for adequate dispersion. Muds containing these additives had to be prepared at a mixing plant and hauled to the rig site. Make up costs were also high with true oil mud due to higher volume percentage of oil plus the large additions of asphalt. Water contamination was an acute problem causing excessive viscosity and water wetting of solids, necessitating replacement of the system or at least dilution with new mud.

Adjusting Oil Based Muds Properties 

Water contamination of invert emulsions required adjustment of mud properties by the addition of oil and emulsifiers. The principal components in the oil muds could not be added to adjust a single property without affecting most of the other mud properties. Single additives to adjust or control specific mud properties were not available at the time to provide the flexibility and versatility needed for lower cost.

Water in oil emulsions

The original inverts were composed of the same basic ingredients as the true oil muds. The concentrations of materials differed however. Calcium and magnesium soaps were used along with asphalt in small concentrations. Sodium chloride brine was used as the internal phase. The earliest of these systems, No-Blok (Magcobar) and Kenex (Ken Corp., later IMC) did not have any other additives. Although they were more flexible (rheologically) than the true oil mud, they were not as stable. In recent years the base oil in OBMs has been replaced by synthetic muds such as esters and ethers. These muds are generally called synthetic or psuedo oil based muds.

The water in invert emulsion muds is dispersed as small droplets throughout the oil. Emulsifiers coat the droplets, preventing them from coalescing and making the mud unstable (i.e. larger water droplets will settle out and break down the emulsion). A calcium or magnesium fatty acid soap is often used as an emulsifier in an oil based mud. The long hydrocarbon chain of the soap molecule tends to be soluble in oil while the ionic portion tends to be soluble in water. When soap is added to a mixture of oil and water the molecule takes up the position shown in Figure.1 .
 Water droplets dispered in a continuous oil phase.
 Fig.1 Water droplets dispered in a continuous oil phase. 
This reduces the surface energy of the interface and keeps the water droplets in the emulsion. Other types of emulsifiers can also be used (e.g. naphthenic acid soaps and soaps from tree sap). The effectiveness of an emulsifier depends on the alkalinity and electrolytes present in the water phase and also on the temperature of the mud. To increase the stability the water droplets should be as small and uniform as possible. This is done by shearing the mud by agitators. When oil is added the stability increases, since the distance between droplets becomes greater. This causes a decrease in viscosity. For good mud properties there must be a balance between oil and water. The water droplets help to: 
  • Support the barite
  • Reduce filter loss
  • Build viscosity and gel strength

Wettability Control

When a drop of liquid is placed on a solid it will either: 
  • Spread itself over the surface of the solidor 
  • Remain as a stable drop 
The shape that the drop takes up depends on the adhesive forces between the molecules of the solid and liquid phases. The wettability of a given solid surface to a given liquid is defined in terms of the contact angle q (Figure 2). 
  • For a solid/ liquid interface which exhibits a small contact angle (<90 by="" degrees="" figure="" in="" is="" li="" liquid.="" nbsp="" preferentially="" solid="" the="" thus="" water="" wet.="" wetted="">
  • If q = 0 degrees, then the solid is totally water wet. 
When two liquids are present and brought into contact with a solid, one of the liquids will preferentially wet the solid. Most natural minerals are water wet. When water wet solids enter an emulsion the solids tend to agglomerate with the water, and settle out. To overcome this problem surfactants are added to the oil phase to change the solids from being water wet to being oil wet. The soaps added as emulsifiers will also act as wettability control agents, but special surfactants are more effective. 
The stability of the emulsion can be tested by measuring the conductivity of the mud. The stronger the emulsion the higher the voltage required for an electric current to flow. 
A loose emulsion is often due to water wet solids or free water. When water-wet solids are present the surface of the mud becomes less shiny and the cuttings tend to stick to each other and blind the shale shaker. Barite added for density control must also be oil wet otherwise the particles will tend to settle out.

Contact angles in three phase systems oil based mud
Fig.2 Contact angles in three phase systems

Balanced activity 

The activity of a substance is its affinity or potential for water. All rocks which contain clay will absorb water to some extent. This is because there is a difference between the activity of the shales and the activity of the mud. If the chemical potentials of the shale and the mud were equal the shale would not absorb any water. This would eliminate any swelling of the clays, leading to borehole instability. For balanced activity in an oil-based mud the activity of the mud (Aw) must be adjusted to equal the activity of the formation being drilled. CaCl2 or NaCl may be added to the mud to keep Aw above 0.75. The activity of the shale can be measured by taking samples from the shaker.

Viscosity control 

Excessive viscosity in an oil based mud may be the result of: 
  • Too much water content - When water is properly emulsified it behaves like a solid. As the water fraction increases so does the viscosity 
  • Drilled solids - The solids content affects viscosity in oil based mud in the same way as Water Based Mud. The build up of fine solids(e.g. due to diamond Drill Bit) may produce high PV, YP and gel strengths. Finer shaker screens (120 mesh) should be used to reduce this effect. Water wet solids may also cause problems with high YP
It is recommended that pilot tests should be done to assess the implications of adding drilling chemicals to the mud to control viscosity. Emulsifiers and wetting agents may be added to reduce viscosity. 

Water and special viscosifiers (organically treated bentonite) may be added to the mud to increase viscosity.

Filtration control

Only the oil phase in oil based mud is free to form a filtrate, making an oil based mud suitable for formations which must not be damaged. The fluid loss is generally very small with oil based muds (less than 3cc at 500 psi and 300 degrees F). During the test there should never be water present in the filtrate (indicates a poor emulsion). If water is present more emulsifying agent should be added. Excessive filtrate volumes can be cured by adding polymers, lignite etc. (pilot tests are recommended).

Related Papers To Oil Based Mud

Improving the performance of oil based mud and water based mud in a high temperature hole using nanosilica nanoparticles

Oil-based mud (OBM), a non-Newtonian fluid, is known for its superior performance in drilling complex wells as well as combating potential drilling complications. However, the good performance may degrade under certain circumstances especially because of the impact of chemical instability at an elevated temperature. The performance of nanosilica is then studied by comparing each of the nanosilica-enhanced mud systems with the corresponding basic mud system, taking the fluid loss and rheological properties as the benchmark parameters. Nanosilica shows a positive impact on OBM and WBM, as the presence of nanosilica in the mud systems can effectively improve almost all their rheological properties.

Oil-Based Muds for Reservoir Drilling: Their Performance and Cleanup Characteristics

This paper evaluates the performance of a standard oil-based mud (OBM) to drill horizontal wellbores, concentrating on its formation-damage characteristics and the flow-initiation pressures (FIP's) required for production to flow through the filter cake. For heterogeneous reservoirs, damage is relatively low in low-permeability rocks, but the FIP is high. Conversely, for high-permeability rocks, the FIP is low but formation damage is relatively high. If the drawdown pressure available from the reservoir is low, the scenario exists where inflow will occur predominantly from the higher-permeability formations, which could be damaged badly, but little inflow will occur from relatively undamaged lower-permeability rocks. In terms of maximizing production, this is obviously a less-than-optimal scenario.