Introduction and Basic Concepts of (Drilling) - Part1

FUNCTIONS OF A DRILLING FLUID
Drilling engineers know that muds have many functions in the drilling operations. At any one time in the operation, one function may be more important than the other functions for that drilling interval, which is why a mud program is essential in well planning. Some publications may list ten to fifteen different functions of a drilling fluid. Many of these are variations of the same function.

This section will discuss: 
• Generating hydrostatic pressure downhole
• Removing cuttings from the bit and transporting them to the surface
• Controlling invasion of filtrate into the formation
• Stabilizing the formation mechanically
• Inhibiting chemically Hydrostatic Pressure Filling a drill hole with a gas or fluid will inevitably generate a hydrostatic head or pressure as illustrated in Figure 1. This is calculated by the use of the following equation:

Hydrostatic Head or Mud Pressure (Pm) =

(Conversion constant) ' (Mud weight or density) ' (True vertical depth)

FIGURE 1. Hydrostatic Head

The concept of specifically controlling the density to regulate the downhole pressure was introduced in 1921. Barite was then used to increase the density. Downhole pressure needs to be controlled for two reasons.

• The drilled rock must be supported and stabilized.
• The pressure of gases and fluids in the rock must be exceeded so they do not enter the wellbore. 

The second reason is particularly important for safety. As the mud density supports the rock, excessive downhole pressure can also damage it by “fracturing” it in the manner that a hose pipe can be split by too high a pressure.

A key to a successful operation is the knowledge of the formation stresses, formation strength, and pore pressures, so that the correct mud weight and casing depths can be selected. Hopefully, the casing depths will isolate problem areas.

 The pressure applied by the mud column will depend on whether it is static or being pumped. The additional pressure used to overcome frictional losses and viscous effects generates additional pressure, referred to as equivalent circulating density (ECD).

 ECD = Hydrostatic Head + ÆP 

A complete discussion of ÆP is in Module LAB203.05 on Rheology.
planning. Some publications may list ten to fifteen different functions of a drilling fluid. Many of these are variations of the same function

Cuttings Transport
Drilling progress can only be made if the cuttings are removed from the wellbore and separated and discarded at the surface. Cuttings removal involves four steps:

• Removing the cuttings away from the area of the bit where the cuttings are generated 
• Transporting the cuttings to the surface in the annular space between the drill pipe and the wall of the hole
• Suspending the cuttings at the surface to allow separation
• Suspending the cuttings in the hole when the pump is off

Moving cuttings away from the bit is controlled by the pump rate and bit hydraulics, not by any particular mud property. Enough volumetric flow is needed to sweep the bit and move the cuttings into the annulus. Figure 2 shows a typical chip removal from the face of the bit.

FIGURE 2. Chip Removal From Bit Face

High drill rates can overload the volumetric flow past the face of the bit, resulting in regrinding the chips cut by the bit. Also, especially at shallow depths, high drill rates can load up the annulus, resulting in excessive hydrostatic head. Annular flow rate, therefore, is critical for proper hole cleaning. 

Transporting the cuttings up the annulus is also dependent on having the proper rheological properties (viscosity) as well as flow rate. The flow regime, turbulence or laminar, is also important for good hole cleaning. Figure 3 shows typical cuttings removal patterns in the annulus. A complete discussion of hole cleaning and rheology is given in Module LAB 203.05 on Rheology.

FIGURE 3. Typical Cuttings Removal Patterns in the Annulus

The rheology module also covers the suspension properties. Maintaining both drilled cuttings and weight material in suspension requires gel strengths and low-shear rate viscosity. Without adequate suspension, excessive fill after trips or connections can cause problems.

Control Filtrate Invasion 
The fluid loss properties of a mud may effect the penetration rate, hole instability, formation damage, and differential sticking.

The total amount of fluid lost to the formation is dependent upon:
• Pressure difference between mud column and pore pressure
• Base fluid viscosity
• Formation permeability
• Filter cake permeability
• Temperature

Mud filtration is even more critical when drilling depleted zones and higher permeability formations. Fluid invasion can also occur in fractured formations, especially if the mud hydrostatic head is significantly higher than the formation pressure.

Filtrate invasion into producing zones is one of the leading causes of formation damage, resulting in reduced production. Not only the amount of filtrate but the type is important. For this reason, an inhibitive fluid may be used. Oil muds or salt-based water muds are often used to minimize damage.

The filter cake quality is essential in maintaining good fluid loss control. Poor filter cakes and high fluid losses can lead to excess drag and differential sticking. Figure 4 shows the formation of the filter cake. The basis of good filtration control in a water-based mud is to have sufficient, high quality bentonite. Bentonite forms a tight, low-permeability filter cake. Sometimes, however, fluid loss control additives must be used to reach very low fluid loss levels. Also at high temperatures, further additives may be needed to overcome temperature degradation.

FIGURE 4. Formation of Filter Cake

Specific products and mud formulations will be covered in detail in other modules of the course. A discussion of the API fluid loss test procedure is covered in the Module LAB203.02 on Drilling Fluid Testing.

Mechanical Stabilization
Shale instability takes many forms and can result in a variety of problems while drilling. These problems range from minor delays and increased daily costs to stuck pipe and lost wellbores. The following list contains some of the more common problems experienced.

• Fill and bridges – Excess fill on bottom after trips or connections or bridges and tight hole encountered higher up the hole on trips. These problems result in expensive reaming operations, mud treatment, and possibly excessive bit wear or damage. You must be certain that this problem is not caused by lack of proper hole cleaning, either from poor rheology or low pump output.

• Ineffective hole cleaning.– Additional formation entering the wellbore due to failure may overload the capacity of the annular circulating flow rate to carry all the solids from the wellbore.

• Stuck pipe – Probably the most costly result of hole instability is a stuck pipe. If the pipe is stuck, it will, at the least, take some rig time to correct and, at worst, result in the hole being lost.

• Increased hole volume – Severely washed-out holes may result in higher mud costs, increased cement requirements, and poor cement jobs.

• Logging difficulties – Washed-out hole and fill and bridges can seriously interfere with getting good electric logs and sidewall cores.

Wellbore Drilling Terms
Through the years, various terms have been used to describe the problems associated with wellbore instability while drilling. Different parts of the world used different words to describe the same phenomena. The following are some of the terms and their usual interpretation.

Sloughing, Running, Heaving – These words describe the general condition of excess pieces of formation showing up on the shale shaker. They are usually associated with hard dewatered shales.
Mud Making Shales, Gumbo, Bentonitic Swelling, Plastic Flow – These conditions usually refer to drilling through formations high in bentonite or other swelling clay content such as recent volcanic sediments. These clays may disperse into the mud or extrude into the wellbore. Plastic flow also is encountered when drilling massive salt sections.
Fractured Shales – This term is usually applied to tectonically stressed areas (mountainous) with known highly faulted or highly dipped formations.
Pressured Shales, Gas-bearing Sands – These terms are applied when excess shale volume is experienced along with gas intrusions. It is usually caused by insufficient mud weight.

Categories of Well Instability
For purposes of this module, the following four categories of well instability will be used and illustrated in Figures 5 through 8.

• Sloughing – Sloughing consists of unconsolidated, weak, or loose formation that may fall into the wellbore due to the geological nature of the formation. Sloughing usually occurs at shallow depths. The hole may or may not be enlarged, since weak formations will flow and fill in the areas being washed away.

• Induced sloughing – This refers to formation that falls into the wellbore as a result of water-wetting clays or washing out cementitious materials (salts, etc.). Dissolving cementitious materials usually occurs at shallow depths and results in a washed-out hole. Water wetting and clay swelling may occur at greater depths when hydratable clays are present.

• Heaving – This formation instability is caused by formation pressures higher than the hydrostatic head from the mud. Hydratable clays in the formation may aggravate this condition. The pieces of heaving shale crossing the shaker are usually square or rectangular and vary in size from cuttings size to several inches. Often the pieces have rounded edges. This indicates that the piece is slipping and tumbling in the annulus, causing the edges to wear.

• Spalling – Spalling or splintering occurs when pressures in the formation cause the hole to close radially. This can occur at any depth and typically is found in highly tectonically stressed areas. Plastic flow of massive salt sections is a special case of this phenomena. Splintered shale pieces are usually long and narrow with sharp edges and points. Many times they are slightly curved, showing the shape of the wellbore.

FIGURE 5. Hole Failure – Sloughing Shale

FIGURE 6. Hole Failure – Induced Sloughing Shale

FIGURE 7. Hole Failure – Heaving Shale

FIGURE 8. Hole Failure – Spalling Shale

The most common cause of unstable formations is mechanical instability resulting from the imbalance of formation stresses. The stress balances created in the earth over millions of years is disrupted when a hole is drilled into it. These internal formation stresses have to be rebalanced or the wellbore will collapse. Most formations have enough strength that they do not immediately collapse. Given sufficient time, however, most formations will eventually start collapsing. There is a time-value associated with hole instability based on the geology of the formation, the mud density, and the type of mud in the hole. Figure 9 illustrates the origins of stress in rocks.

FIGURE 9. Origins of Stress in Rocks

The stresses being applied are:
• Overburden pressure, S – The overburden pressure is the pressure exerted by the weight of the earth above the element. The overburden pressure depends upon the mineral make-up of the formation and, in general, can be assumed to be about 1.0 psi/ft. It is not linear, however, with depth because the formation density tends to increase with depth as a result of compaction and reduction in porosity.

• Pore pressure, Po – The pore pressure is the fluid pressure within the pore spaces of the formation helping to support the overburden pressure. If the fluids in the pore spaces are interconnected and have not been trapped, the pore pressure is equivalent to the hydrostatic head of the water column above the formation element shown in Figure 9. Pore fluids are predominantly salt water, so the pore pressure in normally pressured formations is taken to be a column of water with sea water salinity. This is equal to a gradient of about 0.046 psi/ft. On a graph, the pressure gradient is approximately a straight line although the temperature gradient will influence the density.

• Matrix stress, s – The matrix stress is the portion of the overburden pressure that is supported by the physical structure of the formation. It can be resolved into three components that are perpendicular to one another (one vertical stress and two horizontal ones). This is shown for a piece of rock in Figure 10. In most cases, only the overall matrix stress can be examined since the three components must be measured in situ. (Approximations of the three principal stresses have been done in the past from log and seismic-derived data). The total matrix stress for normally pressured formations is about 0.054 psi/ft.

FIGURE 10. Stresses in Drilled Hole

The magnitude of the pressures acting on the element shown in Figure 11 can be established from the simplified equation

S = P + s

For example, given a 10,000-foot well, normally pressured

 S = 1.0 psi/ft ´ 10,000 ft = 10,000 psi

P = 0.048 psi/ft ´ 10,000 ft = 4,650 psi

s = S – P = 5,350 psi

FIGURE 11. Elliptical Hole as the Result of Unequal Radial Stress

• Wellbore stress – The drilling of a hole in the stressed rock generates a new higher stress field or “hoop stress”, which is related to the stresses at right angles to the wellbore. These stresses decay to the initial stress as you move away from the wellbore. This is shown in Figure 10. Filling the hole with mud exerts a pressure (Pm) that reduces the tangential stress.

The drilling technique uses the minimal mud weight to balance additional weight to the pore pressure and then to reduce the rock stress to a level where it is stable. This is also illustrated in Figure 10. No attempt is made to balance the stress perfectly as the higher mud weight will slow down the rate of penetration. 

This technique puts the rocks under stress and leads to failure. Subsequent reaction of rocks with the drilling fluid is often enough to stress the rocks to a point where they fail. The adsorption of water takes some time and contributes to the time dependency of the stability of rocks. 

Formations that contain high levels of the clay mineral montmorillonite will retain the water while under the overburden pressure. This means that the pore fluids will bear a disproportionately high amount of the overburden pressure. Also, the matrix stress will be low. The mud weight will have to be increased to hold back the formation. 

Tectonically stressed areas pose a special problem since these formations have been fractured and folded. Fractures may allow the penetration of whole fluid that can transmit pressures into the formation, causing it to weaken and fall in. Also, when folded formations are drilled, part of the wellbore face may be highly compressed while another part may be in tension. It is nearly impossible to calculate the relative principal stresses in this case, but there is usually one that will approach zero. Mud weights higher than indicated by pore pressure analysis (gas pressure) are usually needed to stabilize the formation in this situation. The amount of mud weight needed can only be determined in the field on a case-by-case basis.

Whenever the stresses at right angles to the wellbore are not equal, the wellbore will fail in the direction of least stress and produce an oval or elliptically shaped hole as shown in Figure 11. This situation will often be encountered when drilling deviated holes because the vertical stress tends to be larger than the horizontal stress. Tectonically stressed areas may also show the same phenomena. Directional drilling in an oval hole is difficult, but this problem cannot be overcome.

The following factors are involved in shale instability from physical causes:

 • Density – The proper density is the most important factor in shale stability. 

• Erosion – Proper hydraulics, annular and bit, must be maintained in formations prone to instability. Once instability is started, by erosion or other factors, it can be difficult to stop.

 • Pressure surges/swabs – Excessive surges and swabs when tripping or running pipe can initiate instability. Rocks are much weaker in tension so they are prone to fracture, which can occur when running pipe too fast into the hole. The fractured rock is more likely to produce problems later on. 

• Direct contact – Minimize pipe whip by maintaining the proper pipe tension and rotation. 

• Fluid invasion – In fractured formations, whole mud can invade and cause instability. In some cases, high fluid losses can also help weaken a formation.
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