Drilling Fluid: Primary Well Control Under normal conditions the drilling fluid in the wellbore is the primary Well Control be it drilling mud or workover brine. One of its prime reasons for being there is to hold back the formation pressure. This is done by it having a higher pressure gradient in the fluid then the formation. If the formation gradient is not known we can work off the gradient of salt water until such time as a test  is preformed and  more accurate information is forthcoming. The drilling/workover fluid is kept a little higher that that of the expected formation fluids but not so high that it will break down or damage the formations. It must also be remember the the fluid column exert a pressure against the complete open wellbore section, although this pressure varies with depth so does that of the formation. Should the formation at any given depth be unable to except the pressure being applied and the fluid level in the wellbore drop, formation that were being held in place could very well start to intrude into the wellbore. Such intrusions can be in varied forms. Splinters from the side of the hole can be blown off or lose "unconsolidated" formation start to full in. formation fluid may start to enter the wellbore.  The differential in pressure is commonly referred to as a trip margin or safety margin. As the well gets deeper so the mud gradient will be raised. But not excessively unless one is expecting a much higher formation pressure (gradient). The closer you can keep the ratio between both drilling fluid and formation gradient the faster it will drill.  The hydrostatic head of the fluid column can be worked out using the formula (True vertical depth * .052 * the weight of the drilling fluid in pounds per gallon): And as the name says this is with the fluid static. If the fluid is moving (being pumped) this then changes to what is known as the dynamic fluid head.  The dynamic fluid head is grater than that of the hydrostatic head due to the friction of the fluid moving back up the wellbore and is cause by the the resistant to flow created by the walls of the outer wellbore and the pipe in the string . we call this The Annular Pressure Loss) (APL) This pressure create an added pressure to the fluid at the bottom of the hole. This same pressure loss is used as a safety factor when a well is being circulated out during a kill and will remain in place as long as the fluid is being moved.    A kick is killed by Constant Bottom Hole Pressure. this pressure is created by using  constant pump stroke to maintain a constant drill pipe pressure. this pressure is known as the final circulating and is maintained and controlled by the use of a choke and the APL until the New Kill fluid has replaced all the old drilling fluid from the wellbore A kick would be described as an influx from the formation that enters the well bore where the primary well control fluid has a lower pressure gradient than that of the formation. The longer it is allowed to come in the harder, it is to control.  Not all flows are kicking. Sometimes a well will take fluid and give it back there are many reasons for this. Too higher circulating pressure with a high annular pressure lose could force fluid into the pores and hold it there until such pressures are release. " the circulation stopped" such a flow will not show while circulating. Imbalance fluid, expansion of fluid or pipe. bottoms up after a round trip can often confuse people. Such flows are short lived,  however all should be investigated.  The key to primary well control is keeping the fluid weight correct. Gas cut fluid coming from long gas sands will very often cut the fluid weight back. Gas in cutting will do the same. However, if treated before re-circulating will have no effect, as all the gas will be take out.  If to server one should stop drilling and circulate on the choke as fluid being belched out over the bell nipple could reduce the hydrostatic head to the point that the well will kick. Such sand should be "controlled drilled"  Oil will cut the mud weight.  If the fluid is hot, it may be hard to detect. Water will lower the mud weight if drilling with fresh water mud, salt water starts to contaminate it, both the viscosity, and chlorides will rise. It is therefore important that a consent check on the weight of the fluid be made both in and out of the hole. The mud watcher or shaker man play a very big part in well control Beside keeping a check on the mud weight they should keep an eye on the shape and size of the cutting. As often when the primary well control starts to brake down other indication come over the shaker. Shape and size of cutting could be the first indication of a problem. Long splinter type slivers will often indicate the mud weight being too low. The splinters will often come from the wall of the hole Blown of by the formation pressure.  A pump pressure drops could be another indication of mud problems but can also indicate the start of other problems. Pump pressure could also indicate a kick, as often it will drop if the bit penetrate a gas sand A rise in the mud temperature another indicator. Why? Heat is often caused by friction. What would cause friction in a hole. Tight hole. Tight hole could be the swelling of the walls this would indict the hydrostatic head of the fluid column was not holding back the wall. So you see that stuff you keep dumping every time you open the wrong valve is not only expensive. but it also important and like the blood in your veins it plays an awful big part in the drilling and safety of the well.