Lost circulation caused by nature can occur within three types of reservoir rocks

• High permeability formations

• Natural fractured reservoir

• Cavernous formations

High Permeability Formations

High permeability rocks such as coarse sands, gravels can cause lost circulation because drilling mud can easily move into pore spaces. When you have the problem with these kinds of reservoirs, you need to bridge openings as soon as possible. The largest pore space should be bridged off first with rigid granular lost circulation material (LCM). Then, the second seal is to bridge the remaining spaces left from the big LCM with flaked and deformable fibrous LCM. In this case, the challenge thing about curing losses is to select the proper size of LCM to match the opening spaces in reservoirs.

Natural Fractured Reservoirs

Natural fractures and faults can be seen in any reservoir. Typically, this kind of reservoir is found in salt domes and mountain font areas. If you drill in the area where you know the existence of natural fracture reservoirs, the lost circulation material and plan of attack must be in place all the time because the lost circulation can be happened so easy. Additionally, the natural fractures can be widen by excessive hydrostatic pressure.

Cavernous Formations

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Lost circulation or lost returns is the situation happened when drilling mud loses into formation downhole and it is one of biggest drilling problems which can affect safety and expense. The lost circulation can be partial or total loss and it is occurred by either natural or induced causes. When people talk about losses, the severity of the situation can be just only few barrels or hundred barrels an hour. Uncontrolled lost circulation can lead to well control situation and loss of the well. Moreover, drilling mud lost down hole can severely damage the formation because the drilling mud changes permeability of reservoir rocks.

 

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Water phase activity is a relative measure of how easy water can evaporate from the drilling mud. This term frequently comes with shale stability. The water phase activity is measured by determining the water vapor in the air space of a closed container of liquid solution. The evaporation rate of pure water is quicker than salt dissolved solution. The reason why salt solution has slow evaporation rate is that water molecules are bound therefore there is less free water to evaporate.

Pure water has the water phase activity of 1.0. The solution with salt dissolved has less water activities than pure water depending on how much concentration of salt solution is and what type of salt in the solution is. For instant, saturated calcium chloride (CaCl2) has an activity of 0.38 and saturated sodium chloride (NaCl) solution has an activity of approximately 0.76. Shale with average 10 – 20 % water concentration has the water activities around 0.6 to 0.98.

Reference books: Drilling Fluid Books

Most drilling mud chemicals can be dissolved into the liquid phase until they reach a maximum solubility limit called “a saturation point”. Soluble solid will stop dissolving into the liquid phase when, it reaches the saturation point.

Let’s take a look at the room temperature condition (25C). Before reaching the saturation point, potassium chloride (KCl) will dissolve in the water up to 24% by weight but sodium chloride (NaCl) can be dissolved into water up to 26% by weight. Formate is the most soluble salt. For example, potassium formate has a saturation point of 74% by weight and cesium formate can reach 83% by weight. Some chemicals can be dissolved in very minimal. For instant, gypsum/anhydrite can dissolve and has calcium ions into solution only 800 ppm.

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We will start topics regarding the chemistry concepts of drilling mud. As you know, the drilling mud is compound mixture of several chemicals as polymer, oil, water, salt, etc. The drilling mud is changed when it is exposed to downhole condition where there are high temperature and high pressure. The first topic which we would like to discuss in this post is “solubility of drilling mud”.

Solubility of Drilling Mud

It is know that salt in the drilling fluid dissolves in water and we will discuss further to understand the mechanism which makes solubility happen. Salt (NaCl) is composed of sodium ion (Na+) and chloride (Cl -) and they hold together by ionic bonds. When the NaCl is dissolved, the ionic bonds are broken. What’s more, the hydrogen bonds holding water molecules together are parted when chloride and sodium ions move between the water molecules because water molecules are polar (see the image below).

The positive charge of sodium molecules (Na +) attract the negative end of water (O-) and the water come together on all side until the sodium molecules (Na +) is floating in solution. Additionally, the same reaction happens when the negative ions of chloride (Cl-) attracts the positively charged hydrogen molecules as you can see from the illustration below.

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The following guidelines will demonstrate good drilling practices for barite sag.

Maintain good mud properties – The low shear yield point (3 or 6 RPM reading on FANN-35 viscometer) is a good indicator for barite sag. Typically, you should maintain the low shear yield point above 7 to 15 lb/100 ft2.

Monitor mud density – while circulating, you should monitor mud weight at least every 25 minutes in order to observed changes in mud weight. Pump pressure can also tell us if there is barite sag by monitoring stand pipe pressure. If fluctuation of stand pipe pressure is observed, you can suspect your well face with the problem. Moreover, if you have PWD in the BHA, monitor barite sag is much easier because changes of down hole pressure due to unconformity mud weight can be easily observed.

Keep sufficient flow rate – in a dynamic condition, barite settling can form like cutting beds at the bottom of the well during low annular velocity in the annulus. You need to have high flow rate which can transport barite bed. Best practices of hole cleaning which are circulation at high flow rate, pipe reciprocation can effectively remove the barite bed.

Minimize time for tripping – the barite beds can slump during static condition therefore minimizing tripping time will reduce severity of barite sag. Thicker barite bed tends to create a lot of drilling operation problems.

Maximize rotating time and minimize sliding time – Barite sag is most likely happened while sliding because the drill string is eccentric and static. Conversely, when the drillstring is rotated, rotational movement stir up barite bed; therefore, the chance of barite sag is reduced. Back ream full stand after sliding help remove barite sag too.

Avoid excessive dilution – dilution with base fluid will reduce mud rheology (PV/YP). The best way to do dilution is to gradually dilute the system over time. Excessive dilution can drastically increase the barite sag.

Reference books: Drilling Fluid Books