Бурение грунтовых зондов, установка энергетических колодцев

The primary functions of a drilling fluid are:

• Remove cuttings from the Wellbore

• Prevent Formation Fluids Flowing into the Wellbore

• Maintain Wellbore Stability

• Cool and Lubricate the Bit

• Transmit Hydraulic Horsepower to Bit

The drilling fluid must be selected and or designed so that the physical and chemical properties of the fluid allow these functions to be fulfilled. However, when selecting the fluid, consideration must also be given to:

• The environmental impact of using the fluid

• The cost of the fluid

• The impact of the fluid on production from the pay zone

The main functions of drilling fluid and the properties which are associated with fulfilling these functions are summarised in Table 1, and discussed below.

Function	Physical/Chemical Property
Transport cuttings from the Wellbore	Yield Point, Apparent Viscosity, Velocity, Gel Strength
Prevent Formation Fluids Flowing into the Wellbore	Density
Maintain Wellbore Stability	Density, Reactivity with Clay
Cool and Lubricate the Bit	Density, velocity,
Transmit Hydraulic Horsepower to Bit	Velocity, Density, Viscosity

Table 1 Function and Physical Properties of Drilling Fluid

a. Remove cuttings from the Wellbore

The primary function of drilling fluid is to ensure that the rock cuttings generated by the drilllbit are continuously removed from the wellbore. If these cuttings are not removed from the bit face the drilling efficiency will decrease. It these cuttings are not transported up the annulus between the drillstring and wellbore efficiently the drillstring will become stuck in the wellbore. The mud must be designed such that it can:

• Carry the cuttings to surface while circulating

• Suspend the cuttings while not circulating

• Drop the cuttings out of suspension at surface.

The rheological properties of the mud must be carefully engineered to fulfil these requirements. The carrying capacity of the mud depends on the annular velocity, density and viscosity of the mud. The ability to suspend the cuttings depends on the gelling (thixotropic) properties of the mud. This gel forms when circulation is stopped and the mud is static. The drilled solids are removed from the mud at surface by mechanical devices such as shale shakers, desanders and desilters (see Section 5 below). It is not economically feasible to remove all the drilled solids before re-circulating the mud. However, if the drilled solids are not removed the mud may require a lot of chemical treatment and dilution to control the rheological properties of the mud. For a thorough treatment of the rheology of drilling fluids refer to the chapter on Drilling Hydraulics.

b. Prevent Formation Fluids Flowing into the Wellbore

The hydrostatic pressure exerted by the mud colom must be high enough to prevent an influx of formation fluids into the wellbore. However, the pressure in the wellbore must not be too high or it may cause the formation to fracture and this will result in the loss of expensive mud into the formation. The flow of mud into the formation whilst drilling is known as lost circulation. This is because a certain proportion of the mud is not returning to surface but flowing into the formation.

The pressure in the wellbore will be equal to: P = 0.052 x MW x TVD

where,

P = hydrostatic pressure (psi)

MW = mud density of the mud or mud weight (ppg)

TVD = true vertical depth of point of interest = vertical height of mud column

(ft)

The density of the mud may be expressed in either of the following units:

To obtain the following Units of density multiply the Units in the first colom by:

	S. G.	psi/ft	ppg
S. G.	1.0	0.433	8.33
psi/ft	2.31	1.0	19.23
ppg	0.12	0.052	1.0

Table 2 Conversion of Commonly used Units of Density

Example:

A mudweight of 12 ppg is equivalent to a mudweight of 12 x 0.052 = 0.624 psi/ft A mudweight of 1.4 S. G. is equivalent to a mudweight of 1.4 x 0.433 = 0.606 psi/ft

The mud weight must be selected so that it exceeds the pore pressures but does not exceed the fracture pressures of the formations being penetrated. Barite, and in some cases Haemitite, is added to viscosified mud as a weighting material. These minerals are used because of their high density:

Mineral Density (S. G.)

TOC o "1-5" h z Silica (Sand) 2.5

Ca CO3 2.5

Barite 4.2

Haemitite 5.6

The relatively high density of Barite and Haemitite means that a much lower volume of these minerals needs to be added to the mud to increase the overall density of the mud. This will mean that the impact of this weighting material on the rheological properties of the mud will be minimised.

When drilling through permeable formations (e. g. sand) the mud will seep into the formation. This is not the same as the large losses of fluid which occurs in fractured formations, discussed above. As the fluid seeps into the formation a filter cake will be deposited on the wall of the borehole. Some fluid will however continue to filter through the filter cake into the formation. The mud and the filtrate can damage the productive formations in a number of ways. The loss of mud can result

in the deposition of solid particles or hydration of clays in the pore space. The loss of filtrate can also result in the hydration of clays. This will result in a reduction in the permeability of the formation. In addition to damaging the productivity of the formations the filter cake can become so thick it may cause stuck pipe. The ideal filter cake is therefore thin and impermeable.

c. Maintain Wellbore Stability

Data from adjacent wells will be useful in predicting borehole stability problems that can occur in troublesome formations (eg unstable shales, highly permeable zones, lost circulation, overpressured zones)

Shale instability is one of the most common problems in drilling operations. This instability may be caused by either one or both of the following two mechanisms:

• the pressure differential between the bottomhole pressure in the borehole and the pore pressures in the shales and/or,

• hydration of the clay within the shale by mud filtrate containing water.

The instability caused by the pressure differential between the borehole and the pore pressure can be overcome by increasing the mudweight. The hydration of the clays can only be overcome by using non water-based muds, or partially addressed by treating the mud with chemicals which will reduce the ability of the water in the mud to hydrate the clays in the formation. These muds are known as inhibited muds.

d. Cool and Lubricate the Bit

The rock cutting process will, in particular with PDC bits, generate a great deal of heat at the bit. Unless the bit is cooled, it will overheat and quickly wear out. The circulation of the drilling fluid will cool the bit down and help lubricate the cutting process.

e. Transmit Hydraulic Horsepower to Bit

As fluid is circulated through the drillstring, across the bit and up the annulus of the wellbore the power of the mud pumps will be expended in frictional pressure losses. The efficiency of the drilling process can be significantly enhanced if approximately. 65% of this power is expended at the bit. The pressure losses in the system are a function of the geometry of the system and the mud properties such as viscosity, yield point and mud weight. The distribution of these pressure losses can be controlled by altering the size of the nozzles in the bit and the flowrate through the system. This optimisation process is discussed at length in the chapter on Drilling Hydraulics.

It is possible that in order to meet all of these requirements, and drill the well as efficiently as possible, more than one type of mud is used (e. g. water-based mud may be used down to the 13 3/8" casing shoe, and then replaced by an oil-based mud to drill the producing formation).

Some mud properties are difficult to predict in advance, so the mud programme has to be flexible to allow alterations and adjustments to be made as the hole is being drilled, (e. g. unexpected hole problems may cause the pH to be increased, or the viscosity to be reduced, at a certain point).

1.2 Types of Drilling Fluid

The two most common types of drilling fluid used are water based mud and oil based mud. These muds will be discussed in detail in Section 3 and 4 below but as a general statement, Water-based muds (WBM) are those drilling fluids in which the continuous phase of the system is water (salt water or fresh water) and Oil- based muds (OBM) are those in which the continuous phase is oil. WBM’s are the most commonly used muds world-wide. However, drilling fluids may be broadly classified as liquids or gases (Figure 1). Although pure gas or gas-liquid mixtures are used they are not as common as the liquid based systems. The use of air as a drilling fluid is limited to areas where formations are competent and impermeable (e. g. West Virginia). The advantages of drilling with air in the circulating system are: higher penetration rates; better hole cleaning; and less formation damage. However, there are also two important disadvantages: air cannot support the sides of the borehole and air cannot exert enough pressure to prevent formation fluids entering the borehole. Gas-liquid mixtures (foam) are most often used where the formation pressures are so low that massive losses occur when even water is used as the drilling fluid. This can occur in mature fields where depletion of reservoir fluids has resulted in low pore pressure.

Drilling Fluid

Gas/Liquid Mixture

Foam

Liquids

Gas Air

Water Based Mud

Oil Based Mud

Freshwater Mud

Salt Sat. Mud

Inhibited Mud

Full Oil	Invert Emulsion	Pseudo
Mud	Mud	Mud

KCL-PHPA	Polyol	Silicate
Mud	Muds	Mud

Figure 1 Types of Drilling Fluid

Water based muds are relatively inexpensive because of the ready supply of the fluid from which they are made — water. Water-based muds consist of a mixture of solids, liquids and chemicals. Some solids (clays) react with the water and chemicals in the mud and are called active solids. The activity of these solids must be controlled in order to allow the mud to function properly. The solids which do not react within the mud are called inactive or inert solids (e. g. Barite). The other inactive solids are generated by the drilling process. Fresh water is used as the base for most of these muds, but in offshore drilling operations salt water is more readily available. Figure 2 shows the typical composition of a water-based mud.

1.0

Clays ± 5% (Active solids) Sand, limestone etc. ± 5% (Inactive low density solids) I Barite 5-10 % (Inactive high density solids) Water ±80% (Fresh or salt water)

0.8

0.6

0.4

0.2

Figure 2 Composition of typical water — based mud

0.0

Figure 3 Composition of typical oil-based mud

^ Clays, sand, etc. ± 3% | Salt ±4% Barite ±9% | Water ±30% Oil 50-80%

The main disadvantage of using water based muds is that the water in these muds causes instability in shales. Shale is composed primarily of clays and instability is largely caused by hydration of the clays by mud containing water. Shales are the most common rock types encountered while drilling for oil and gas and give rise to more problems per meter drilled than any other type of formation. Estimates of worldwide, nonproductive costs associated with shale problems are put at $500 to $600 million annually (1997). In addition, the inferior wellbore quality often encountered in shales may make logging and completion operations difficult or impossible.

Over the years, ways have been sought to limit (or inhibit) interaction between WBMs and water-sensitive formations. So, for example the late 1960s, studies of mud-shale reactions resulted in the introduction of a WBM that combines potassium chloride (KCl) with a polymer called partially-hydrolyzed polyacrylamide — KCI-

PHPA mud. PHPA helps stabilize shale by coating it with a protective layer of polymer. The role of KCI will be discussed later.

The introduction of KCI-PHPA mud reduced the frequency and severity of shale instability problems so that deviated wells in highly water-reactive formations could be drilled, although still at a high cost and with considerable difficulty. Since then, there have been numerous variations on this theme, as well as other types of WBM aimed at inhibiting shale.

In the 1970s, the industry turned increasingly towards oil-based mud, OBM as a means of controlling reactive shales. Oil-based muds are similar in composition to water-based except that the continuous phase is oil. In an invert oil emulsion mud (IOEM) water may make up a large percentage of the volume, but oil is still the continuous phase. (The water is dispersed throughout the system as droplets). Figure 3 shows the typical composition of OBM’s.

OBM’s do not contain free water that can react with the clays in the shale. OBM not only provides excellent wellbore stability but also good lubrication, temperature stability, a reduced risk of differential sticking and low formation damage potential. Oil-based muds therefore result in fewer drilling problems and cause less formation damage than WBM’s and they are therefore very popular in certain areas. Oil muds are however more expensive and require more careful handling (pollution control) than WBM’s. Full-oil muds have a very low water content (<5%) whereas invert oil emulsion muds (IOEM’s) may have anywhere between 5% and 50% water content.

The use of OBM would probably have continued to expand through the late 1980s and into the 1990s but for the realization that, even with low-toxicity mineral base-oil, the disposal of drilled cuttings contaminated by OBM can have a lasting environmental impact. In many areas this awareness led to legislation prohibiting or limiting the discharge of these wastes. This, in turn, has stimulated intense activity to find environmentally acceptable alternatives and has boosted WBM research.

To develop alternative nontoxic muds that match the performance of OBM requires an understanding of the reactions that occur between complex, often poorly characterized mud systems and equally complex, highly variable shale formations.

In recent years the base oil in OBMs has been replaced by synthetic fluids such as esters and ethers. Oil based muds do contain some water but this water is in a discontinuous form and is distributed as discrete entities throughout the continuous phase. The water is therefore not free to react with clays in Shale or in the productive formations.

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