One of the most important tools used by drillers isn’t made of steel or rubber.
The tool we’re talking about is drilling mud. Although not as visible or obvious as a drill bit, mast, or drawworks, drilling mud is the real workhorse of the rig. And being a workhorse, can lead to all sorts of drilling challenges when it isn’t properly formulated.
Drilling Mud
Basic water based drilling mud is made from water mixed with bentonite clay (usually sodium montmorillonite), a naturally occurring clay substance, to form a thick slurry. A variety of additives, including thickeners, thinners, densifiers, lubrication, anti-foaming agents, pH controls, and other chemicals, are mixed with the drilling mud to improve its performance.
Most importantly, the density of drilling mud can be adjusted by adding dense materials such as barite.
Mud serves many purposes. These include:
- Cooling and lubricating: A rotating drill bit will generate a lot of friction, and that means a lot of heat. As the drill bit heats up the bit metallurgical properties changes and becomes less effective. Drilling mud circulates through the drill bit at a high rate on its journey through the borehole, keeping the drill bit cool as well as keeping it lubricated.
- Cleaning: Drilling mud scours the cuttings from the bottom of the well the bit just dug up, allowing the drill to keep drilling as well as to move those cuttings from the bit back to the surface. And when drilling stops, the mud will quickly thicken, keeping those cutting within the borehole in suspension and from raining back down on the bottom of the borehole.
- Hydraulic power transmission: Drilling mud pressure can be used as an energy source for downhole equipment such as mud motors and power generators.
- Pressure containment: The pressure exerted by drilling mud due to its hydrostatic, dynamic, and surface pressures against a formation stops potential high pressure fluids within that formation from escaping during drilling which could, under extreme conditions, cause a blowout.
- Wellbore stability: Drilling mud also cakes on the wall of the wellbore, helping stabilize the wellbore and the exposed formation. It also reduces the chances of the drill string getting stuck downhole.
The most important role of mud in terms of the safe operation of a well is pressure containment. Many underground formations contain fluids under high pressure, and it is the drilling mud that keeps these fluids and gases from entering the drill string and annulus. Containing this pressure is known as maintaining well control, and it is a challenging but critical component of drilling.
Pressure and the Mud Weight Window
In order to contain the pressure, drillers need to make sure the density of the mud is within a certain range – called the mud weight window.
Let’s dive into that a bit.
Have you ever swum to the bottom of the deep end of a swimming pool and felt the pressure on your ears? That’s the pressure of the water above you trying to get inside your air-filled ears. The deeper the water, the higher the pressure. The same thing is true with pore pressure in the earth. The pores are like your ears. The fluid pushing down is much deeper than the swimming pool, in fact it may be thousands of feet deep, and it is trying to get into those spaces with great force. To the extent the pore spaces are connected, almost no matter how small the pore throats, it succeeds.
The amount the pressure increases with depth is called the pressure gradient. Pressure is force divided by area. If you keep the area the same but increase the force or weight, for instance by swimming deeper into the pool or going deeper into the earth, the pressure in the fluid goes up.
The pressure gradient is related to the density of the fluid. If you have a pool of slightly salty water, or a column of rock whose pore space is filled with brine, the pressure goes up reliably by about 0.44 psi for every foot you go below the surface. Let’s say for the sake of simple math, our oil and gas reservoir is at a depth of 1000 feet, and the pore space above the reservoir is filled with brine. The pressure in the fluid at the reservoir depth would be 440 psi above atmospheric pressure, found by multiplying 0.44 psi/ft times 1,000 ft. This gradient of 0.44 psi/ft is what we call a normal pressure gradient or the hydrostatic gradient. Fresh water exerts a pressure of 0.433 psi/ft.
Hydrostatic indicates the pressure you would expect at the bottom of a static (not flowing) column of water of a certain height. Flowing fluids adds a dynamic pressure to the system.
This concept of gradients can be related to pressure in the rock as well. The lithostatic gradient (litho refers to rock) refers to the pressure gradient caused by the rock and the fluids in the pore space combined. The lithostatic gradient under typical circumstances on land is approximately (and conveniently) 1 psi/ft. Therefore, if we were to go to our reservoir at 1000 feet of depth again, the pressure at the bottom of that column of rock would be 1000 psi (1 psi/ft times 1000 ft). This is the pressure required to hold up not only the solid component of the rock but also the fluid contained in the pores. This lithostatic gradient is also what we term in geology the vertical stress gradient. In offshore operations, the lithostatic gradient is smaller than one psi/foot because seawater, which makes up some of the total depth, is much less dense than rock and thus pushes down on the reservoir less powerfully.
How does pore pressure affect our oil and gas operations?
Well, firstly, in order to produce oil and gas, the hydrocarbons need to be under pressure in order to give them the energy to flow into our wellbore so we can bring them to the surface. The higher the pressure the better fluid flow in that regard. However, this flowing toward the wellbore can be a problem while we’re drilling.
Essentially the wellbore is providing an open conduit through which the reservoir fluids from underground can escape. If the pressure in the wellbore is less than the pressure inside the reservoir, the fluids will flow into the wellbore and possibly to the surface.
While we are drilling, we don’t really have any way to accommodate oil and gas that might flow up to us – we haven’t connected any pipelines or tanks to the wellbore yet. Therefore, we usually design our drilling process to prevent fluid from flowing into the wellbore. We do this by making the pressure in the wellbore higher than in the formation. This is done by making the gradient of pressure in the wellbore fluid (the drilling mud) a bit higher than the gradient of pore pressure in the reservoir.
So if you were drilling at, let’s say 10,000 feet now, and you knew the reservoir was normally pressured (remember 0.44 psi/ft), you would calculate a pore pressure of 4400 psi. If we used brine as our drilling fluid, it would have that same 0.44 psi/ft pressure gradient in the wellbore, we would be able to exactly balance the reservoir pressure and prevent flow into the wellbore. This state is called balanced drilling.
Normally we would want some margin of safety to be sure the flow wouldn’t occur, so we might drill slightly overbalanced, at say 0.5 psi/ft of pressure gradient in the wellbore (instead of 0.44). We can do this adjustment by making the fluid in the wellbore more dense, usually by adding some solids such as barite into the drilling fluid. It’s roughly the same volume as before, but it weighs more per gallon. As it turns out, pounds per gallon is how we measure mud weight. You’ll see it abbreviated as PPG throughout the course.
If we happen to drill underbalanced, which means the pressure in the wellbore is less than the pore pressure in the formation, then oil and gas can flow into the wellbore. The gas is what’s dangerous, in that it is highly compressible. So as the gas moves up the wellbore in an underbalanced drilling situation, it expands more and more rapidly as the pressure is reduced on it (it expands exponentially to be correct), reducing the density and mass of the drilling fluid and further reducing the wellbore pressure.
Flow from the formation then accelerates because the rate is dependent on the difference between pore pressure and wellbore pressure. As the wellbore fills with expanding gas, it exerts less pressure against the formation gases, allowing even more gas to come into the hole, further reducing the density of the mud, allowing even more flow – it’s a vicious cycle. This is why blowouts can be sudden. It isn’t that the signs were not there, it is just that the sudden expansion occurs as the formation gas (called a “kick”) gets close to the surface. The expansion rapidly increases leading to a rapid expulsion of drilling fluid from the borehole which is classic “blowout” event you see in every Hollywood movie involving the oil field. Pretty soon the flow is out of control and we can have a blowout. The graph below illustrates the pore pressure gradient. Because of the above concerns, this is also the minimum pressure we would normally want to maintain in the well. We will continue to build this graph out as we go down the page.
Because of that possibility, we don’t usually drill underbalanced on purpose, unless we have special equipment set up to accommodate gas that comes to the surface. But sometimes as we drill, the natural pore pressure gradient may increase unexpectedly. We could move from one layer that is normally pressured to a deeper layer that is overpressured. This overpressure is often a consequence of compaction due to deep burial of sediment, and if there is a very low permeability clay above the compacting zone, the pore fluids can’t escape and are instead compressed along with the rock.
This compression increases the pore pressure gradient beyond 0.44 psi/ft, which gives us an over-pressured formation. Some reservoirs may have pore pressure gradients of as high as 0.8 or 0.9 psi/ft – resulting in pressures that almost balance the weight of the entire overburden above them. The absolute limit on this pore pressure gradient is the overburden gradient, or 1 psi/ft, because if that gradient were exceeded, the pore pressure would lift the earth’s crust.
It turns out that this pressure gradient limit is often even less than the overburden gradient.
Why?
In a fluid, we know that at any depth the pressure is the same in all directions. If you were (hypothetically) sitting at the bottom of the ocean, you would feel a horizontal pressure squeezing you that would be equal to the vertical pressure squeezing you. If the pressures became unequal in any direction, the fluid would flow to balance that pressure and maintain equilibrium, getting the pressures back to being the same in all directions. This state is termed isotropic pressure or stress.
Iso = the same
tropic = orientation or direction
Isotropic pressure is pressure that is the same in every direction
Rock obviously isn’t like water, because of its strength to resist flow, so it can maintain differences in the horizontal and vertical stress, or to say it another way, rock can support Anisotropic Stress.
Isotropic is the same in every direction. Anisotropic is not the same in every direction or it could be said to be direction dependent.
The reason for getting into this is to say that the limits on pore pressure and the limits on the pressure we can sustain in our wellbore (which is the mud pressure) are dictated by the least stress in the earth. If stresses were isotropic, we could assume the maximum limit is 1 psi/ft. However, typically, one of the horizontal stresses is less than the vertical stress. So that’s the one we have to pay attention to.
This least horizontal stress is described as the fracturing pressure, and if the mud pressure exceeds fracturing pressure, the mud causes the rock to fail by opening up a tensile fracture emanating from the wellbore. These fractures act as pressure relief valves in the subsurface – when they open, mud escapes the wellbore, and the wellbore pressure will go down as drilling mud leaks out of the wellbore into the formation. The next graph illustrates the fracture pressure gradient. Since we don’t want fractures emanating from the borehole while we’re drilling, we’re trying to stay under fracture pressure.
Accidental fracturing and mud loss during drilling can lead to problems. If we fracture the formation while drilling, the drilling fluids escape into the subsurface formations rather than returning to the surface through the annulus of the wellbore – this is known as lost returns or lost circulation. The fluid level in the annulus then falls, reducing the wellbore pressure, creating under balanced conditions and allowing gas to migrate to the wellbore. Now you have two problems. Just as described in the underbalanced drilling situation, the gas compounds the problem and that can lead to a blowout.
As you can see, we have to plan wisely. Leaving a buffer zone between the pore pressure and fracture pressure is advisable. On our graph, that buffer zone can be illustrated like this:
So, to review, if we drill with a wellbore pressure gradient that is too low (because our mud density is too low), we can have gas flowing into the wellbore because we are not counterbalancing the pore pressure gradient, and this could lead to blowout if not corrected quickly. The solution is to increase the mud density to increase the pressure gradient in the wellbore. But if we overcorrect, we can exceed the fracture gradient, opening a fracture and losing returns, reducing the level of mud column in the annulus and again promoting gas flow that could cause blowout.
We don’t want either of these incidents to happen!
The potential for these two different types of well control problems reveals the importance of properly predicting pore pressure and properly weighting the drilling mud throughout the entire drilling process.
Safe drilling requires us to stay between these upper and lower limits at all times within the open formation section of the borehole – between pore pressure and fracturing pressure – and this range is what we call the mud weight window. Properly weighted mud, falling within the mud weight window, including the (formerly yellow) buffer zones, can be illustrated like this:
Let’s do one more review of this graph. The left-most line represents the formation pore pressure, the dotted lines represent margins of safety in our mud weight, the green section shows the pressure exerted by the drilling mud, and the right-most solid line shows the pore pressure required to fracture the rocks. The space between the pore pressure and fracture pressure (green and yellow combined) is the mud weight window.
Because the mud density is generally constant over the entire wellbore, it can only really be adjusted in steps. The density adjustments related to each step usually occur when the mud weight required to prevent fluids from entering the bottom of the well is too high for the upper portion of the well, meaning it would fracture the rocks.
To prevent this, a string of casing is installed, which isolates the upper formations from the mud weight, allowing mud weight to be increased deeper in the well. That is why the window zig-zags like a lightning bolt.
Choosing those points at which new casing strings must be added (set points) is called casing design, and that is where we’re headed next.
Images: “Mud Grate” by Michael Black; “Illustrations” by Top Energy Training; “Graphs” by Top Energy Training