Mud Loss Calculation

Mud Loss Calculation

The length of the annulus or the length of the low-density fluid and mud 

density of the lost circulation can be calculated based on annulus capacity 

behind the drill collar. If the lost circulation volume is smaller than the annu￾lus volume against the drillpipe, the length of the annulus (i.e., loss height) 

can be expressed in terms of the volume of the low-density fluid pumped 

to balance the formation pressure, and annulus capacity. Mathematically,

If Vl

 < Van_dp, the length of the low-density fluid required in order to bal￾ance the formation pressure is given by:

Problems Related to the Mud System

 Introduction

The drilling-fluid system is one of the well-construction processes that 

remains in contact with the wellbore throughout the drilling operation. 

Advances in mud technology have made it possible to implement a sustain￾able system for each interval in the well-construction process. As a result, 

the associated problems have been reduced significantly. Reduction of the 

cost of the drilling fluid, which is an average of 10% of the total tangible 

costs of well construction, is a great challenge. Mud performance can affect 

overall well-construction costs in several ways. In addition, failure to select 

and formulate the mud correctly will create many problems. This chapter 

addresses the problems related to drilling-fluid system and proposes the 

solutions. However, there are some problems which are not directly related 

to the mud system. These problems are discussed in another chapter. An 

identified problem well caused by drilling-fluid can be considered as par￾tially solved. Therefore, identifying any problem turns out to be a crucial 

task. The logical relationship of cause and 

effect must be well organized to

the identified related problems. Mixing their logical relationship may lead 

to hindering further problem analysis tasks.

3.1 Drilling Fluids and its Problems with Solutions

A correctly formulated and well-maintained drilling system can contribute 

to cost containment throughout the drilling operation by enhancing the 

rate of penetration (ROP), protecting the reservoir from unnecessary dam￾age, minimizing the potential for loss of circulation, stabilizing the well￾bore during static intervals, and helping the operator remain in compliance 

with environmental and safety regulations. Drilling fluids can be reused 

from well to well, thereby reducing waste volumes and costs incurred for 

building new mud. Although currently reusing doesn’t diminish costs at 

any appreciable manner, as more operators practice this recycling, the eco￾nomics of recycling will improve. In addition, the introduction of envi￾ronment-friendly additives is amenable to recycling and minimization of 

environmental footprints. To the extent possible, the drilling-fluid system 

should help preserve the productive potential of the hydrocarbon-bearing 

zone(s). Minimizing fluid and solids invasion into the zones of interest 

is critical to achieving desired productivity rates. The drilling fluid also 

should comply with established health, safety, and environmental (HSE) 

requirements so that personnel are not endangered and environmentally 

sensitive areas are protected from contamination. Drilling-fluid compa￾nies work closely with oil-and-gas operating companies to attain these 

mutual goals.

Drilling fluid (also called drilling mud) is an essential part in the rotary 

drilling system. Most of the problems encountered during the drilling of 

a well are directly or indirectly related to the mud. To some extent, the 

successful completions of a hydrocarbon well and its cost depend on the 

properties of the drilling fluid. The cost of the drilling mud itself is not 

very high. However, the cost increases abruptly for the right choice, and 

to keep proper quantity and quality of fluid during the drilling operations. 

The correct selection, properties and quality of mud is directly related to 

some of the most common drilling problems such as rate of penetration, 

caving shale, stuck pipe and loss circulation, and others. In addition, the 

mud affects the formation integrity and subsequent production efficiency 

of the well. More importantly, some toxic materials are used to improve 

the specific quality of the drilling fluid that are a major concern to the 

environment. Among others, this addition of toxic materials contaminates 

the underground system as well as the surface of the earth. Economically, it 

                      also translates into long-term liability as stricter regulations are put in place 

with increasing awareness of environmental impacts of toxic chemicals.

Therefore, the selection of a suitable drilling fluid and routine control 

of its properties are the concern of the drilling operators. The drilling and 

production personnel do not need detailed knowledge of drilling fluids. 

However, they should understand the basic principles governing their 

behavior, and the relation of these principles to drilling and production per￾formance. They should have a clear vision of the objectives of any mud pro￾gram, which are: (i) allow the target depth to be reached, (ii) minimize well 

costs, and (iii) maximize production from the pay zone. In a mud program, 

factors needing to be considered are the location of well, expected lithol￾ogy, equipment required, and mud properties. Hence this chapter refers to 

the author’s textbook Fundamentals of Sustainable Drilling Engineering for 

details in the basic components of mud, its functions, different measuring 

techniques, mud design and calculations, the updated knowledge in the 

development of drilling fluid and future trend of the drilling fluid. It is 

important because acquiring this knowledge will lead to an understanding 

of the real causes, and solutions related to drilling-fluid system.

3.1.1 Lost Circulation

During drilling of hydrocarbon wells, drilling fluids are circulated through 

the drill bit into the wellbore for removal of drill cuttings from the well￾bore. The fluids also maintain a predetermined hydrostatic pressure to 

balance the formation pressure. The same drilling fluid is usually recon￾ditioned and reused. When comparatively low-pressure subterranean 

zones are encountered during a drilling operation, the hydrostatic pres￾sure is compromised because of leakage into the zones (Figure 3.1). This 

phenomenon is commonly known as “lost circulation.” So, lost circulation 

is defined as the uncontrolled flow of mud into a “thief zone” and presents 

one of the major risks associated with drilling. However, different authori￾ties and researchers defined the lost circulation in a diversified manner. 

According to oilfield glossary it is defined as “the collective term for sub￾stances added to drilling fluids when drilling fluids are being lost to the 

formations downhole”. Howard (1951) defined it as follows: “loss of cir￾culation is the uncontrolled flow of whole mud into a formation, some￾times referred to as a “‘thief zone.’” It is also defined as “the reduced or 

total absence of fluid flow up the annulus when fluid is pumped through 

the drillstring (Schlumberger, 2010). The complete prevention of lost cir￾culation is impossible. However, limiting circulation loss is possible if cer￾tain precautions are taken. Failure to control lost circulation can greatly

                    increase the cost of drilling, as well as the risk of well loss. Moreover, lost 

circulation may lead to loss of well control, resulting in potential damage 

to the environment, fire and/or harm to personnel. The risk of drilling a 

well in areas known to contain potential zones of lost circulation is a key 

factor in planning to approve or cancel a drilling project. The successful 

management of lost circulation should include identification of potential 

“thief zones”, optimization of drilling hydraulics, and remedial measures 

when lost circulation occurs.

The problem of lost circulation was apparent in the early history of the 

drilling industry and was magnified considerably when operators began 

drilling deeper and/or depleted formations. The industry spends millions 

of dollars a year to combat lost circulation and the detrimental effects it 

propagates, such as loss of rig time, stuck pipe, blowouts, and frequently, 

the abandonment of expensive wells. Moreover, lost circulation has even 

been cited as the cause for production loss and failure to secure produc￾tion tests and samples. On the other hand, controlling lost circulation can 

lead to plugging of production zones, resulting in decreased productivity. 

The control and prevention of lost circulation of drilling fluids is a prob￾lem frequently encountered during the drilling of oil and gas wells. During 

the drilling of wells, fractures that are created or widened by drilling fluid 

               pressure are suspected of being a frequent cause of lost circulation. Of 

course, natural fractures, fissures, and vugs can create lost circulation even 

during underbalance drilling, in which fluid pressure doesn’t play a role in 

lost circulation.

There are four types of formation and/or zones that can cause loss of 

circulation: (i) cavernous or vugular formations, (ii) unconsolidated zones, 

(iii) high permeability zones, and (iv) naturally or artificially fractured 

formations. Circulation loss can take place when a comparatively high 

pressure zone (subterranean) is encountered, causing cross flows or under￾ground blowouts. Whenever the loss of circulation crops up, it is noticed by 

the loss of mud, and the loss zones are classified according to the severity of 

the loss: (i) “Seepage” with less than 10 bbl/hour loss, (ii) “Partial Loss” for 

10 to 500 bbl/hour loss, (iii) “Complete Loss” for greater than 500 bbl/hour 

loss. The lost circulation problem requires corrective steps by introducing 

lost circulation materials (LCM) into the wellbore to close the lost circula￾tion zones. Many kinds of materials can be used as LCM. They include low￾cost waste products from the food processing or chemical manufacturing 

industries. Figure 3.1 shows some examples of LCM as listed here.

Historically, mud losses have been dealt with by dumping some mica 

or nut hulls down a wellbore. There are numerous reports of ‘throwing 

in everything available’ to stop the extreme cases of mud loss. However, 

as the drilling operation becomes increasingly sophisticated and great 

feats are achieved in terms of drilling in difficult terrains and deep wells, 

simplistic solutions are no longer applicable. The industry is accelerating 

its activities in deepwater and depleted zones, both of which present nar￾row operating limits, young sedimentary formations, and high degree of 

depletion overbalanced drilling. These newfound prevailing conditions are 

susceptible to creating fractures and thus lead to lost circulation. Among 

others, drilling through and below salt formations presents a host of tech￾nical challenges as well. The thief zone at the base of the salt can introduce 

severe lost circulation and well control problems. This often results in loss 

of the interval or the entire well. The lost time treating severe subsalt losses 

can last for several weeks, with obvious cost implications, especially for 

deepwater drilling operations. Salt formations are common for oil-bearing 

formations that can be termed pre-salt if older or subsalt if younger. The 

oil-bearing formations of below salt in the Gulf of Mexico are mainly sub￾salt, whereas those in offshore Brazil are a mix of subsalt and pre-salt. The 

difficulty in managing a drilling operation through a salt formation lies 

in the fact the salt composition varies greatly. For instance, for the Gulf 

of Mexico, the salt formation contains mainly NaCl. On the other hand, 

the offshore Brazil salt formations have predominantly MgCl2

, which is 

                               far more reactive than NaCl. Salt formations are typical of other forma￾tions that are equally plastic and mobile can also be encountered during 

drilling. Controlling losses in this zone has proven to be extremely difficult 

as it involves matching the composition of the mud with that expected 

downhole, in order to minimize leaching of the in-situ salt into the drilling 

mud – a process that would create imbalance in the fluid system. Also, the 

plasticity of the salt may cause shifting. Therefore, the mud weight should 

be as close to overburden gradient, otherwise salt may shift into wellbore, 

leading to pipe being stuck. Very few lost circulation remedies have been 

successful, especially when using invert emulsion drilling fluids. Typically, 

a salt formation should be drilled with salt-tolerant water-based drilling 

fluids or with invert emulsion fluids. Deeper salt zones can be drilled with 

oil-based fluids that can be replaced with water-based mud after the salt 

formation has been passed. Such formations are available in the Bakken 

basin of the United States. In drilling through salt formations, consider￾ations of density, salinity, and rheology are of paramount importance. The 

density consideration relates to maintaining bore stability. The salinity 

relates to preventing leaching from the salt formation as well as prevent￾ing intrusion and salt deposition in the wellbore. The rheology consider￾ation relates to cleaning the salt cuttings and keeping them afloat during 

the return of the mud.

When dealing with induced fractures the problem is even more com￾plicated because the shape and structure of induced formation fractures 

are always subject to the nature of the formation, drilling and mechanical 

effects, as well as geological influences over time. When the overbalance 

pressure exceeds the fracture pressure, a fracture may be induced and lost 

circulation may occur. By incorporating a lost circulation material (LCM) 

in the fracture to temporarily plug the fracture, the compressive tangential 

stress in the near-wellbore region of the subterranean formation increases, 

resulting in an increase in the fracture pressure, which in turn allows the 

mud weight to operate below the fracture pressure.

LCM are often used as a background treatment or introduced as a con￾centrated “pill” to stop or reduce fluid losses. The main objective when 

designing an effective treatment is to ensure that it is able to seal fractures 

effectively and stop losses at differential pressure. The differential pressure 

is caused by the elevated drilling fluid pressures compared to the pore fluid 

pressure in regular drilling operations or drilling fluid pressures exceeding 

the wellbore fracture pressure. The design of the LCM treatment hinges 

upon particle size distribution (PSD) as the most important parameter 

(Ghalambor et al., 2014; Savari et al., 2015). Al Saba et al., 2017) compared 

various PSD methods and proposed one that is the most accurate. Table 3.1 

                                 lists these methods. The most recent selection criteria are the most accurate 

and they stipulate that D50 and D90 should be equal or greater than 3/10th 

and 6/5th of the fracture width, respectively. Al Saba et al. (2017) reported 

that nutshells can plug fractures with relatively low concentrations whereas 

graphite and calcium carbonate are effective only at higher concentrations.

In general, there is a general fascination for sphericity and roundness of 

LCM, needs to be taken into consideration when analyzing PSD. As such, 

artificial LCM have gained popularity.

Recent advances in LCM have been in developing an array of materials with 

a range of sizes, shapes, and specific gravities. The new generation of these 

materials involve smart materials, such as the one patented by Halliburton 

(Rowe et al., 2016). Rowe et al. introduced Micro-electro-mechanical sys￾tems lost circulation materials (MEMS-LCM). A typical usage of this tech￾nology would involve drilling at least a portion of a wellbore penetrating 

the formation with a drilling fluid that comprises a base fluid. This can be 

followed by several cycles of MEMS-LCM, and another set of LCM, wherein 

the MEMS-LCM and the LCM are substantially similar in size, shape, and 

specific gravity. After this cycle, measurements can be made to determine 

concentrations of the MEMS-LCM in the drilling fluid before circulating 

the drilling fluid through the wellbore and after the MEMS-LCM treatment, 

thus finalizing the concentration of the next phase of MEMS-LCM.

                 One condition of paramount importance in sealing induced fractures 

(i.e., to change shape and size as per wellbore pressure changes) is having 

the LCM reaching the tip of the fracture. Related to the breathing ten￾dency of induced fractures (manifested through pressure pulsation), pres￾sure buffering is another condition that should be fulfilled for effective 

sealing. Preferably, to stop the breathing tendency in a robust manner, the 

pills should be able to increase the fracture gradient at a level sufficiently 

high to avoid reopening the fracture during the subsequent drilling phases. 

Table 3.2 shows several LCM with their characteristic concentrations.

Figure 3.2 shows partial (Figure 3.2a) and total lost-circulation zones 

(Figures 3.2b, and c). In partial lost circulation, mud continues to flow to 

surface with some loss to the formation. Total lost circulation, however, 

occurs when all the mud flows into a formation with no return to surface. 

         A series of lost circulation decision trees is developed to address lost circu￾lation problems for the deepwater prospect (Figure 3.3).

In general, there are three types of basic agents used in the petroleum 

industry to control the loss of circulation problem. These are: (i) bridg￾ing agents, (ii) gelling agents, and (iii) cementing agents. These agents are 

either employed individually or in a blended combination. The bridging 

agents are the ones that plug the pore throats, vugs, and fractures in forma￾tions. Examples of such agents are ground peanut shells, walnut shells, cot￾tonseed hulls, mica, cellophane, calcium carbonate, plant fibers, swellable 

clays ground rubber, and polymeric materials. Bridging agents are further 

classified based on their morphology and these can be: (i) flaky (e.g., mica 

flakes and pieces of plastic or cellophane sheeting), (ii) granular (e.g.,, 

ground and sized limestone or marble, wood, nut hulls, Formica, corncobs 

        and cotton hulls), and (iii) fibrous (e.g., cedar bark, shredded cane stalks, 

mineral fiber and hair). Gelling agents and cementing agents are used for 

transportation and placement of the bridging agent at the appropriate place 

in the circulation loss zone. Highly water absorbent cross-linked polymers 

are also used for loss of circulation problem, as they form a spongy mass 

when exposed to water.

The LCM are evaluated based on their sealing properties at low and high 

differential pressure conditions. In addition, effectiveness of the sealing to 

withstand all kind of pressures during drilling is tested. LCM are classified 

according to their properties and application, such as formation bridging 

LCM and seepage loss LCM. Often more than one LCM type may have to 

be used to eliminate the lost circulation problem.

These drilling problems are encountered both in onshore and offshore 

fields when the formation is weak, fractured and/or unconsolidated. Drilling 

for oil and gas in deep water encounters further challenges, brought about 

by a host of reasons. Some potential hazards are shallow water flow (SWF), 

gas kicks and blowouts, presence of unconsolidated sand formations, shal￾low gas, gas hydrate lost circulation, sea floor washout, borehole erosion, 

etc. These problems are not only hazards on their own; they can also cause 

a significant increase in the total drilling cost. Consequently, alleviation of 

the scope and capacity of these hazards and challenges is imperative for 

safe and economic completion of deep water wells, so that work can be 

done systematically with the least amount of risk.

3.1.1.1 Mechanics of Lost Circulation

Lost circulation frequently occurs in cavernous limestone or in gavel beds at 

relatively shallow depths and under normal pressure conditions. In this type 

of lost circulation, the mud will flow into the cavities at any pressure more 

than the formation fluid pressure without disturbing the reservoir rock. 

This type of lost circulation is prevalent in the cap rock of pier cement-type 

salt domes. Lost circulation under these conditions is essentially a filtration 

problem which can be corrected if the large pore spaces can be plugged.

However, the lost circulation due to abnormal pressures differs in mecha￾nism from the foregoing one. In this case, mud fluid is not lost by filtration 

into large pore spaces in the reservoir rock. The loss of whole mud can take 

place only through formations in which the pore sizes are so large as to 

cause the concept of permeability to lose its generally accepted meaning. 

Lost circulation occurs only when the mud weight is approaching the weight 

of the overburden (15 to 18 lbs per gallon). Loss of circulation in this case 

results from tensile failure of the sediments along lines of weakness, rather

                          than from mud filtration into existing pore spaces. That formation failure 

does occur as evidenced by the conditions under which circulation is lost. 

The usual condition is a sudden and complete loss of returns which may 

occur while drilling, circulating, or while out of the hole to run an electrical 

survey. There are several situations that can result in lost circulation such as 

(i) formations that are inherently fractured, (ii) cavernous (i.e., hollow) for￾mation, (iii) highly permeable zone, (iv) improper drilling conditions, (v) 

induced fractures caused by excessive downhole pressures and setting inter￾mediate casing too high, (vi) improper annular hole cleaning, (vii) excessive 

mud weight, and (viii) shutting in a well in high-pressure shallow gas.

Induced or inherent fractures or fissures may appear as horizontal at 

shallow depth or vertical at depths greater than approximately 762 m. 

Excessive wellbore pressures are developed due to high flow rates (i.e., 

high annular-friction pressure loss) or tripping in too fast (i.e., high surge 

pressure). This can lead to mud equivalent circulating density (ECD). 

Induced fractures can also be caused by improper annular hole cleaning, 

excessive mud weight, and shutting in a well in high-pressure shallow gas. 

Equations (3.1) and (3.2) show the conditions that must be maintained to 

avoid fracturing the formation during drilling, and tripping in, respectively

                 Cavernous formations are often limestones with large caverns. This 

type of lost circulation is quick, total, and the most difficult to seal. High￾permeability formations are potential lost-circulation zones, which are 

shallow sand with permeability greater than 10 Darcies. In general, deep 

sand has low permeability and presents no loss circulation problems. The 

level of mud tanks decreases gradually in non-cavernous thief zones. In 

such situations, if drilling continues, total loss of circulation may occur.

     Partial loss of returns is common in the case of mud loss by filtration. 

However, this is a rare occurrence under abnormal pressure conditions. 

The mechanics of lost circulation of this type are probably most closely 

duplicated in nature by igneous intrusions. In both cases, the formation 

falls under extreme pressure. The only difference is in the source of the 

pressure

Preventive Measures

The complete prevention of lost circulation is impossible because some 

formations, such as inherently fractured, cavernous, or high-permeability 

zones, are not avoidable when encountered during the drilling operation if 

the target zone is to be reached. However, limiting circulation loss is pos￾sible if certain precautions are taken, especially those related to induced 

fractures. There are some preventive measures that can reduce the lost cir￾culation which can be listed as: (i) crew education, (ii) good mud program 

i.e., maintain proper mud weight, (iii) minimize annular friction pressure 

losses during drilling and tripping in, (iv) maintain adequate hole cleaning 

and avoid restrictions in the annular space, (v) set casing to protect weaker 

formations within a transition zone, (vi) updating formation pore pressure 

and fracture gradients for better accuracy with log and drilling data, and 

(vii) study wells in area to be drilled. The rule of thumb is that if antici￾pated, treat mud with LCM.

If loss of circulation happens, there are some actions that need to be 

followed: (i) pump lost circulation materials in the mud, (ii) seal the zone 

with cement or other blockers, (iii) set casing, (iv) dry drill (i.e., clear 

water), and (v) updating formation pore pressure and fracture gradients 

for better accuracy with log and drilling data. Now, once lost-circulation 

zones are anticipated, preventive measures should be taken by treating the 

mud with LCM and preventive tests such as the leak off test and forma￾tion integrity test should be performed to limit the possibility of loss of 

circulation.

Leak-off test (LOT): Conducting an accurate leak off test is funda￾mental to prevent lost circulation. The LOT is performed by closing in 

the well, and pressuring up in the open hole immediately below the last 

string of casing before drilling ahead in the next interval. Based on the 

point at which the pressure drops off, the test indicates the strength of 

the wellbore at the casing seat, typically considered one of the weak￾est points in any interval. However, extending a LOT to the fracture￾extension stage can seriously lower the maximum mud weight that may 

be used to safely drill the interval without lost circulation. Consequently, 

stopping the test as early as possible after the pressure plot starts to break 

over is preferred.

During the LOT, the leak-off test pressure, and equivalent mud weight 

at shoe can be calculated using the following equations.

                               Formation integrity test (FIT): To avoid breaking down the formation, many 

operators perform a FIT at the casing seat to determine whether the wellbore 

will tolerate the maximum mud weight anticipated while drilling the inter￾val. If the casing seat holds pressure that is equivalent to the prescribed mud 

density, the test is considered successful and drilling resumes.

When an operator chooses to perform an LOT or an FIT, if the test fails, 

some remediation effort such as a cement squeeze should be carried out 

before drilling resumes to ensure that the wellbore is competent.

During the FIT, the formation integrity test pressure, and equivalent 

mud weight at shoe can be calculated using the following equations.

                 

Marginal Aquifer Encountered

 An aquifer can be defined as a water-bearing portion of a petroleum res￾ervoir where the reservoir has a water drive. In general, water-bearing 

rocks are permeable which allows fluid to pass while production starts. 

Sometime, drillers encounter marginal aquifer while drilling. This is a 

concern for the people who are engaged with drilling activities because 

drilling fluid may contaminate the aquifer fresh water. Thus, additional 

precautions are needed during the design and execution of the well plan 

to protect fresh water aquifers. In addition, aquifer water can flow into the 

wellbore, and thus contaminate the drilling fluids, which may cause well 

control problem.

Solution: To avoid the above problems, drillers need to confirm that the 

drill bit penetrates the full thickness of the aquifer. It should extend as far 

below it as possible. Install the well screen adjacent to the entire aquifer 

thickness with solid casing installed above and below it. After developing 

the well, install the pump cylinder as low as possible in the well. If a well 

is being completed in a fine sand/silt aquifer within 15–22 m (50–75 ft) of 

ground surface, a 20 cm (8 in) reamer bit is sometimes used (e.g., Bolivia). 

This makes it possible to install a better filter pack and reduces entrance 

velocities and passage of fine silt, clay and sand particles into the well. 

Further, the success can be maximized by adding a small amount of a poly￾phosphate to the well after it has been developed using conventional tech￾niques. The polyphosphate helps to remove clays which occur naturally in 

the aquifer. This clay contaminates the drilling fluid. Therefore, it is also 

important to remove the clay during the process.

2.1.9 Well Stops Producing Water

The reservoir pores contain the natural fluids (e.g., water, oil, gas etc.) at 

chemical equilibrium. It is well known that reservoir rocks are generally 

of sedimentary origin. Therefore, water was present at the beginning and 

thus is trapped in the pore spaces of rocks. This natural fluid (i.e., water) 

may migrate according to the hydraulic pressures induced by geological 

processes that also form the reservoirs. In hydrocarbon reservoirs, some 

of the water is displaced by the hydrocarbon; however, some water always 

remains in the pore space. If there is a water drive from a sea or ocean, then 

it will be acting as a pressure maintenance drive. On several occasions,

during production, sometimes it is experienced that there is no water

production or little water production. Thus, the reservoir pressure drops

down, which affects the hydrocarbon production.

2.1.10 Drilling Complex Formations

Complex reservoir is defined as a distinct class of reservoir, in which fault

arrays and fracture networks exert an overriding control on petroleum

trapping and production behavior, characterized by the interplay of dif￾ferent factors during the development of the reservoir properties of the

field. In such type of reservoir, study on reservoir characteristics become

challenging when the parameters such as fracturing and faulting; complex

distribution of primary and secondary petrophysical properties; relation￾ship between the structural elements and the “matrix” characteristics; and

structural features and diagenetic evolution become significant. Even with

modern exploration and production portfolios commonly held in geologi￾cally complex settings, there is an increasing technical challenge to find

new prospects in drilling, development, and finally to extract remaining

hydrocarbons from the complex reservoirs. Improved analytical and mod￾eling techniques will enhance our ability to locate connected hydrocarbon

volumes and unswept sections of reservoir, and thus help optimize field

development, production rates and ultimate recovery. The depositional

factors play a vital role in this case. The factors can significantly influence

reservoir properties, including initial fluid saturations, residual saturations,

waterflood sweep efficiencies, preferred directions of flow, and reactions

to injected fluids. The permeability barriers may lead to the need to drill

additional infill wells or reposition the locations of such wells, selectively

perforate and inject reservoir units, manage zones on an individual basis,

and revise decisions regarding suitability for thermal recovery operations.

In order to increase the rate of penetration (ROP) and to reduce cost for

drilling complex reservoir, there is a need for special bit structure, drilling

methods and drilling parameters.

2.1.11 Complex Fluid Systems

It is very important to have a comprehensive understanding of the complex

fluid system and its behavior under difference scenarios such as drilling,

production, depletion and developments to increase oil and gas production

as well as safe drilling. Complex fluids and complex fields add more chal￾lenges to the conventional drilling, and scenarios. Therefore, as a petro￾leum engineer, it is essential to understand the challenges, options and best 

practices dealing with the complex reservoir fluid systems both in the oil

and gas industries. A thorough study needs to be done on various aspects

of complex fluids characterization of oil and gas reservoirs to reduce the

risk and uncertainty. Significant complexities exist in oil and gas reservoirs

in terms of reservoir architecture and fluids. Fluid complexities viz. com￾positional gradation and variation, impurities and drastic spatial varia￾tions impact the recovery and production from the field. In the majority of

cases, these complexities are not understood and recognized due to limited

data and lack of analysis and appropriate tools used for capturing the data.

These data are very crucial for reservoir engineering study, processing and

flow assurance in wellbore and pipelines.

2.1.12 Bit Balling

Bit balling is one of the drilling operational issues which can happen any￾time while drilling. Bit balling is defined as the sticking of cuttings to the

bit surface when drilling through Gumbo clay (i.e., sticky clay), water-reac￾tive clay, and shale formations. During drilling through such formation,

as the bit is rotating in the bottom hole, some of this clay get attached to

the bit cones (Figure 2.24). If the bit cleaning is not proper, which happens

usually due to poor hydraulics, more and more of this clay sticks to the bit.

Finally, a stage is reached where all the cones are covered with this clay and

further drilling is not possible. Bit balling can cause several problems such

as reduction in rate of penetration (ROP), increase in torque, increase in

stand pipe pressure (SSP) if the nozzles are also stuck. Since drilling is not 

happening the volume of cuttings on the shale shaker are also reduced.

Personnel may eventually need to pull out of hole the bottomhole assembly

(BHA) to clear the balling issue at the bit.

There are many factors that affect the bit balling. These factors are:

(i) formation – clay stone and shale has a tendency to ball up the bit even

though one uses highly inhibitive water-based mud or oil-based mud;

(ii) calcite content in clay – e.g., highly reactive clays with large cation

exchange capacities; (iii) hydrostatic pressure in wellbore – high hydro￾static pressure (e.g., 5000 – 7000 psi) can induce bit balling issue in water￾based mud; (iv) weight on bit – high weight on bit will have more chance

to create this issue; (v) bit design – poor bit cutting structure and poor junk

slot area in PCD bits contribute to this issue; (vi) poor projection of bit

cutting structure due to inappropriate bit choice or bit wear; (vii) poor bit

hydraulics – low flow rate will not be able to clean the cutting around the

bit; (vii) poor open face volume (i.e., junk slot area) on PDC bits.

If there is a doubt that bit balling is going to be happening, it can be rec￾ognized by: (i) the ROP will decrease more than projection. For example,

if crew drills 100 ft/hr and later the ROP drops to 50 ft/hr without any

drilling parameters changed (e.g. less than expected in soft rock); (ii) drill￾ing torque – drilling torque will be lower than normal drilling torque

since most of the cutters are covered up by cuttings decrease in torque

(i.e., less than expected and may show decrease with time); (iii) weight

on bit – added weight on bit resulting in static or negative ROP reaction;

(iv) standpipe pressure – standpipe pressure increases with no changes in

flow rates or drilling parameters. Balling up around the bit reduce annular

flowing area resulting in increasing pressure (e.g., 100–200 psi with a PDC

bit with no associated increase in flow).

If there is a problem associated with bit balling while drilling, a proper

plan should be implemented to avoid the bit balling. These plans are: (i) Bit

selection – select bit with maximum cutting structure projection (e.g.,

steel tooth bits are better than insert bits because the steel tooth ones have

greater teeth intermesh. Therefore, steel tooth is preferred over similar

insert bit to help clean cutting structure). For the PCD bits, the larger junk

slot area is preferred. (ii) Bit nozzle selection – the bits with high flow tube

or extended nozzles are not recommended. Some jetting action must be

directed onto the bit cutting structure. If the bigger bit size is utilized, we

should not block off the center jet. The center jet will flush all cutting more

effectively. Use tilted nozzles to direct some flow onto the cones of the bit.

(iii) Good hydraulic – hydraulic horse power per cross sectional area of

the bit is the figure which can be utilized for measuring good hydraulic for

bit balling mitigation. Hydraulic horsepower per square inch (HSI) less 

than 1.0 will not be able to clean the bits. It is good practice to have more

than 2.5 of HSI for good bit cleaning in a balling environment. However,

do not maximize flow rate at the expense of HSI. (iv) Drilling fluid – mud

chemical additives such as partially hydrolyzed poly acrylamide (PHPA)

which can prevent clay swelling issue must be added into the water-based

mud system. If feasible, drilling with oil-based fluid will have less chance

of balling up. (v) Weight on Bit (WOB) – the driller should not try to run a

lot of WOB. If WOB is increased and then lower ROP is encountered, the

driller may have bit balling up issue. In such case, the driller should lower

the weight and attempt to clean the bit as soon as possible. Hence, if ROP

falls do not increase WOB as a response. Alert crew to this situation.

Once bit balling has been detected, there are some jobs need to be done

immediately. These jobs can be listed as: (i) Stop drilling and pick up off

bottom – if the drilling operation keeps continuing, it will make the situa￾tion even worse. It is a good practice to stop and pick up off bottom to fix

the issue quickly. (ii) Increase RPM and flow rate – increasing RPM will

spin the cutting around the bit more. Additionally, increase flow rate to the

maximum allowable rate will help clean the bit. (iii) Monitor pressure – if

you see decreasing in standpipe pressure to where it was before, it indicates

that some of cuttings are removed from the bit. (iv) Lower WOB – Drill

with reduced weight on bit. (v) Pump high viscosity pill – pumping high

viscosity pill may help pushing out the cutting. (vi) Fresh water pill – leave

to soak and try to dissolve/loosen balled material. This will help that lithol￾ogy become more silty or sandy, which may help clear bit, and prepare

to trip if these actions are not successful and choose more optimum, bit,

hydraulics nozzle arrangement or mud system.

2.1.13 Formation Cave-in

The main cause of borehole caving (collapse) is simply the lack of suit￾able drilling mud. This often occurs in sandy soils where drillers are not

using good bentonite or polymer. Now, the formation cave-in is defined

as “pieces of rock that come from the wellbore; however, these pieces were

not removed directly by the action of the drill bit”. Cavings can be splin￾ters, shards, chunks and various shapes of rock. These parts normally spall

from shale sections and they become unstable (Figure 2.25). The shape

of the caving can reveal the answer why the rock failure occurs. The term

is typically used in the plural form. The main cause of borehole caving is

lack of suitable drilling mud. This often occurs in sandy soil where drillers

are not using good bentonite or polymer. The problems can be observed

when fluid is circulating but cuttings are not being carried out of the hole. 

In such a situation, if the driller continues to push ahead and drill, the bit

can become jammed. The hole will collapse when the casing team tries to

insert the casing or the huge portion of the aquifer may wash out, mak￾ing it very difficult to complete a good well. The solution is to get some

bentonite or polymer or, if necessary, assess the suitability of natural clay

for use as drilling fluid. Borehole caving can also happen if the fluid level

in the borehole drops significantly. Therefore, it is necessary to have a loss

of circulation or a night time stoppage, and thus slowly refill the borehole

by circulating drilling fluid through the drillpipe. However, pouring fluid

directly into the borehole may trigger caving. If caving occurs while drill￾ing, check if cuttings are still exiting the well. If they are, stop drilling and

circulate drilling fluid for a while. Sometimes part of the borehole caves

while the casing is being installed, preventing it from being inserted to the

full depth of the borehole. When this appears, the casing must be pulled

out and the well redrilled with heavier drilling fluid. When pulling the cas￾ing, no more than 12.19 m (40 ft) should be lifted into the air at any time.

If the driller pulls the pipe more than the specified length, it will cause

thin-walled PVC to bend and crack.

2.1.14 Bridging in Wells

Bridging is defined as “a cave-in from an unstable formation that may trap

the drillstring” (Figure 2.26). Bridging may be the result of insufficient mud

pressure. However, there are different definitions of bridging based on appli￾cations. For example, in the drilling point of view, the bridging in the well

is defined as “to intentionally or accidentally plug off pore spaces or fluid

paths in a rock formation, or to make a restriction in a wellbore or annulus”.

A bridge may be partial or total, and is usually caused by solids (e.g., drilled 

solids, cuttings, cavings or junk) becoming stuck together in a narrow spot

or geometry change in the wellbore. From a well completion point of view,

it can be expressed as “a wellbore obstruction caused by a buildup of mate￾rial such as scale, wellbore fill or cuttings that can restrict wellbore access

or, in severe cases, eventually close the wellbore”. In well workover, bridge is

the “accumulation or buildup of material such as sand, fill or scale, within

a wellbore, to the extent that the flow of fluids or passage of tools or down￾hole equipment is severely obstructed”. In extreme cases, the wellbore can

become completely plugged or bridged-off, requiring some remedial action

before normal circulation or production can be resumed. In perforating/

well completions, bridge plug is outlined as “a downhole tool that is located

and set to isolate the lower part of the wellbore. Bridge plugs may be per￾manent or retrievable, enabling the lower wellbore to be permanently sealed

from production or temporarily isolated from a treatment conducted on an

upper zone”. In well completions, a retrievable bridge plug is described as “a

type of downhole isolation tool that may be unset and retrieved from the

wellbore after use, such as may be required following treatment of an iso￾lated zone”. A retrievable bridge plug is frequently used in combination with

a packer to enable accurate placement and injection of stimulation or treat￾ment fluids. Bridging can be from: (i) cutting slump; (ii) formation cave-in;

(iii) formation extrusion around a tectonically active area or salt diapirs.

A bridge plug is a tool used in downhole applications in the oil drilling

industry. The bridge plug is used in the wellbore or underground to stop

a well from being used. A bridge plug has both permanent and tempo￾rary applications. It can be applied in a fashion that permanently ceases

oil production occurring from the well where it is applied. It can be also

manufactured in a way which makes it retrievable from the wellbore. Thus,

it allows production from the well to resume. They can also be used on a

temporary basis within the wellbore to stop crude oil from reaching an

upper zone of the well while it is being worked on or treated. Bridge plugs

are typically manufactured from several materials that each have their own

applicable benefits and disadvantages. For instance, bridge plugs made

from composite materials are often used in high-pressure applications

because they can withstand pressures of 18,000–20,000 psi (124–137 MPa).

On the other hand, their permanent use tends to lend itself to slippage over

time due to the lack of bonding between the composite materials and the

materials inside the wellbore. Bridge plugs fabricated out of cast iron or

another metal may be perfect for long-term or even permanent applica￾tions. However, they don’t adhere very well in high-pressure situations.

Bridge plugs do not just get placed in a wellbore and left to plug the end.

In fact, placing a bridge plug within a wellbore to either permanently or

temporarily stop the flow of oil or gas is an intensive process that must be

done tactically and skillfully. It must be done while utilizing a bridge plug

tool which is specially designed to place bridge plugs in an efficient manner.

The tool used to place the plug usually has a tapered and threaded mandrel

which is threaded into the center of the bridge plug. It has compression

sleeves placed in succession with each other so that as the tool engages the

plug, the sleeves compress around the plug and the tool rotates the plug

downhole into the wellbore. When the bridge plug is at the desired depth,

the tool is disengaged from the axial center of the plug, and unthreaded

from the cylinder. The tool is removed from the wellbore with the plug

being left in place, as the sleeves have decompressed.

2.1.14.1 Causes of Bridging in Wells

There are several reasons for bridging in the well. For example: (i) Cutting

problems: one of the primary functions of the drilling mud is the efficient

transportation of cuttings to the surface. This function depends essentially

on the fluid velocity and other parameters such as the fluid rheological

properties, cuttings size, etc. The cuttings must be removed from the forma￾tion to allow further drilling. Otherwise, bridging will happen. (ii) Cutting

settling in vertical or near vertical wellbore: vertical or near vertical wells

have inclination less than 35°. It is a well-known fact that drilling mud is a

mixture of fluids such as water, oil or gases and solids (i.e., bentonite, barite

etc.). The solids such as sand, silt, and limestone do not hydrate or react

with other compounds within the mud and are being generated as cuttings

from the formation while drilling. These solids are called inert and must be 

removed to allow efficient drilling to continue. Therefore, solid control is

defined as the control of the quantity and quality of suspended solids in the

drilling fluid to reduce the total well cost. However, some particles in the

mud (i.e., barite, bentonite) should be retained since they are required to

maintain the properties of the mud. The rheological and filtration proper￾ties can become difficult to control when the concentration of drilled solids

(low-gravity solids) becomes excessive. If the concentration of drill solids

increases, penetration rates and bit life decrease. On the other hand, hole

problems increase with the increase of drill solids concentration.

Bridging can happen when cuttings in the wellbore are not removed from

the annulus. This problem can happen when there is not enough cutting

slip velocity in and/or drilling mud properties in the wellbore is bad. When

pumps are off, cuttings fall down the formation bed due to gravitational

force and pack and annulus. Finally, it results in stuck pipe. It is noted that to

clean annulus effectively, the annular velocity must be more than cutting slip

velocity in dynamic condition. Moreover, mud properties must be able to

carry cutting when pumps are on and suspend cutting when pumps are off.

2.1.14.2 Warning Signs of Cutting Setting in Vertical Well

There is an increase in torque/drag and pump pressure

An over pull may be observed when picking up and pump

pressure required to break circulating is higher without any

parameters change

Indications when pipe is stuck due to cutting bed in vertical

well

When this stuck pipe caused by cutting settling is happened,

circulation is restricted and sometimes impossible. It most

likely happens when pump off (making connection) or

tripping in/out of hole.

2.1.14.3 Remedial Actions of Bridging in Wells

Attempt to circulate with low pressure (300–400 psi). Do not

use high pump pressure because the annulus will be packed

harder and you will not be able to free the pipe anymore.

Apply maximum allowable torque and jar down with maxi￾mum trip load. Do not try to jar up because you will create

a worse situation.

Attempt to circulate with low pressure (300–400 psi). Do not

use high pump pressure because the annulus will be packed

harder and you will not be able to free the pipe anymore.

Apply maximum allowable torque and jar down with maxi￾mum trip load. Do not try to jar up because you will create

a worse situation.

2.1.14.4 Preventive Actions

Ensure that annular velocity is more than cutting slip velocity.

Ensure that mud properties are in good shape.

Consider pump hi-vis pill. You may try weighted or

unweighted and see which one gives you the best cutting

removal capability.

If you pump sweep, ensure that sweep must be return to sur￾face before making any connection. For a good drilling prac￾tice, you should not have more than one pill in the wellbore.

Circulate hole clean prior to tripping out of hole. Ensure that

you have good reciprocation while circulating.

Circulate 5–10 minutes before making another connection

to clear cutting around BHA.

Record drilling parameters and observe trend changes

frequently.

Optimize ROP and hole cleaning.

2.1.14.5 Volume of Solid Model

During drilling operation, huge amounts of rock chips are generated due to

the cutting of earth rock. Therefore, it is very important to know the solid

volume of rock fragments that comes to the surface with the drilling mud. In

an ideal situation, all drill solids are removed from a drilling fluid. Under typ￾ical drilling conditions, low-gravity solids should be maintained below 6%

by volume. Drill cuttings are the volume of rock fragments generated by the

bit per hour of drilling. The following equation (Equation 2.20) can be used

to estimate the volume of solids entering to the mud system while drilling.

These solids (except barite) are considered undesirable because

i. They increase frictional resistance without improving lifting

capacity,

ii. They cause damage to the mud pumps, leading to higher

maintenance costs, and

iii. Filter cake formed by these solids tends to be thick and per￾meable. This leads to drilling problems (stuck pipe, increased

drag) and possible formation damage.

The reason that cuttings tend to settle on the low side of inclined wells,

and some indicators of cuttings accumulations, are considered in this sec￾tion. Focus will also be placed on the following: cutting accumulation in

cavities, removal of cuttings from well, guidelines used in deviated wellbore

during cuttings removal in washout, and comparison of published research

done on cuttings removal in washout. Infohost (2012) revealed that accu￾mulation of cuttings can occur in wells that do have adequate hole cleaning.

This is common directional or horizontal wells. Increasing circulating pres￾sure while drilling, or increase in drag pipe causes/363-mechanical-sticking￾cause-of stuck-pipe. It is noted that cuttings accumulation is indicated by:

Reduced cutting on the shale shaker

Increased over pull

Loss of circulation

Increase in pump pressure without changing any mud

properties

While drilling with a mud motor, cutting cannot be effec￾tively removed due to no pipe rotation

Drilling with high angle well (from 35 degrees up)

Abnormality in torque and drag with the help of a trend

(increase in torque/drag)

2.2 Summary

This chapter discusses major drilling problems and their solutions related

to drilling rig and operations only. The different drilling problems encoun￾tered in drilling are explained, along with their appropriate solutions and

preventative measures. Each major problem solution is also complemented

with case studies.

Slow Drilling

Slow drilling refers to the rate of penetration (ROP) which is not in a 

desired level. ROP is defined as the speed at which the drill bit can break 

the rock under it and thus deepen the wellbore. This speed is usually 

reported in units of feet per hour (ft/hr) or meters per hour (Schlumberger 

glossary). ROP is one of the indicators and operational parameters for 

evaluating drilling performance. Slow drilling is the result of this perfor￾mance. In addition, drilling efficiency will have the desired effects on costs 

when all critical operational parameters are identified and analyzed. These 

parameters are referred to as performance qualifiers (PQs). PQs include 

footage drilled per bottomhole assembly (BHA), downhole tool life, vibra￾tions control, durability, steering efficiency, directional responsiveness, 

ROP, borehole quality, etc.

Most of the factors that affect ROP have influencing effects on other 

PQs. These factors can be grouped into three categories: i) planning, ii) 

environment, and iii) execution. The planning group includes hole size, 

well profile, casing depths, drive mechanism, bits, BHA, drilling fluid (i.e., 

type, and rheological properties), flow rate, hydraulic horsepower, and hole 

cleaning, etc. In environmental, factors such as lithology types, formation 

drillability (i.e., hardness, abrasiveness, etc.), pressure conditions (i.e., dif￾ferential, and hydrostatic) and deviation tendencies are included. Weight 

on bit (WOB), RPM and drilling dynamics belong to the execution cat￾egory. ROP can be categorized into two main types: i) instantaneous, and 

ii) average. Instantaneous ROP is measured over a finite time or distance, 

while drilling is still in progress. It gives a snapshot perspective of how a 

particular formation is being drilled or how the drilling system is function￾ing under specific operational conditions. Average ROP is measured over 

the total interval drilled by a respective BHA from trip-in-hole (TIH) to 

pull-out-of-hole (POOH).

It has long been known that drilling fluid properties can dramatically 

impact drilling rate. This fact was established early in the drilling litera￾ture, and confirmed by numerous laboratory studies. Several early stud￾ies focused directly on mud properties, clearly demonstrating the effect of 

kinematic viscosity at bit conditions on drilling rate. In laboratory condi￾tions, penetration rates can be affected by as much as a factor of three by

altering fluid viscosity. It can be concluded from the early literature that

drilling rate is not directly dependent on the type or amount of solids in

the fluid, but on the impact of those solids on fluid properties, particularly

on the viscosity of the fluid as it flows through bit nozzles. This conclusion

indicates that ROP should be directly correlated to fluid properties which

reflect the viscosity of the fluid at bit shear rate conditions, such as the

plastic viscosity. Secondary fluid properties reflecting solids content in the

fluid should also provide a means of correlating to rate of penetration, as

the solids will impact the viscosity of the fluid.

2.1.7.1 Factors Affecting Rate of Penetration

Factors that affect the ROP are numerous and perhaps important variables.

These variables are not recognized well up to-date. A rigorous analysis of

ROP is complicated by the difficulty of completely isolating the variables

under study. For example, the interpretation of field data may involve

uncertainties due to the possibility of undetected changes in rock prop￾erties. Studies of drilling fluid effects are always plagued by difficulty of

preparing two muds having all properties identical except one which is

under observation. While it is generally desirable to increase penetration

rate, such gains must not be made at the expense of overcompensating det￾rimental effects. The fastest ROP does not necessarily result in the lowest

cost per foot of drilled hole. Other factors such as accelerated bit wear,

equipment failure, etc., may raise the cost.

The factors that have an effect on ROP are listed under two general

classifications such as environmental and controllable. Table 2.2 shows the

list of parameters based on these two categories. Environmental factors 

such as formation properties and drilling fluids requirements are not con￾trollable. Controllable factors such as weight on bit, rotary speed, and bit

hydraulics on the other hand are the factors that can be instantly changed.

Drilling fluid is considered to be an environmental factor because a certain

amount of density is required in order to obtain a specific objective to have

enough overpressure so that it can avoid flow of formation fluids. Another

important factor is the effect of overall hydraulics to the whole drilling

operation. This operation is influenced by many factors such as lithology,

type of the bit, downhole pressure and temperature conditions, drilling

parameters and mainly the rheological properties of the drilling fluid. ROP

performance is a function of the controllable and environmental factors.

It has been observed that ROP generally increases with decreased equiva￾lent circulating density (ECD).

Another important term controlling the ROP is the cuttings transport.

Ozbayoglu et al. (2004) conducted extensive sensitivity analysis on cut￾tings transport for the effects of major drilling parameters, while drilling

for horizontal and highly inclined wells. It was concluded that the average

annular fluid velocity is the dominating parameter on cuttings transport,

the higher the flow rate the lesser the cuttings bed development. ROP and

wellbore inclinations beyond 70° did not have any effect on the thickness

of the cuttings bed development. Drilling fluid density have moderate

effects on cuttings bed development with a reduction in bed removal with

increased viscosities. Increased eccentricity positively affected cuttings

bed removal. The smaller the cuttings the more difficult it is to remove

the cuttings bed. It is clear that turbulent flow is better for bed develop￾ment prevention. However, in any engineering study of rotary drilling it

is convenient to divide the factors that affect the ROP into the following

list: i) personal efficiency; ii) rig efficiency; iii) formation characteristics

(e.g., strength, hardness and/or abrasiveness, state of underground for￾mations stress, elasticity, stickiness or balling tendency, fluid content and

interstitial pressure, porosity and permeability etc.); iv) mechanical factors

(e.g., bit operating conditions – a) bit type, and b) rotary speed, and c)

weight on bit); v) hydraulic factor (e.g., jet velocity, bottom-hole cleaning);

vi) drilling fluid properties (e.g., mud weight, viscosity, filtrate loss and

solid content); and vii) bit tooth wear, and depth. However, for horizontal

and inclined well bores, hole cleaning is also a major factor influencing the

ROP. The basic interactive effects between these variables were determined

by design experiments. Variable interaction exists when the simultaneous

increase of two or more variables does not produce an additive effect as

compared with the individual effects. The rate of penetration achieved with

the bit as well as the rate of bit wear, has an obvious and direct bearing on

the cost per foot drilled. The most important variables that affect the ROP

are: i) bit type, ii) formation characteristics, iii) bit operating conditions

(i.e., bit type, bit weight, and rotary speed), iv) bit hydraulics, v) drilling

fluid properties, and vi) bit toot wear.

1. Personal Efficiency: The manpower skills, and experiences are referred

to as personal efficiency. Given equal conditions during drilling/comple￾tion operations, personnel are the key to the success or failure of those

operations and ROP is one of them. Overall well costs as a result of any

drilling/completion problem can be extremely high. Therefore, continuing

education and training for personnel is essential to have a successful ROP

and drilling/completion practices.

2. Rig Efficiency: The integrity of drilling rig and its equipment, and main￾tenance are major factors in ROP and to minimizing drilling problems.

Proper rig hydraulics (e.g., pump power) for efficient bottom and annu￾lar hole cleaning, proper hoisting power for efficient tripping out, proper

derrick design loads, drilling line tension load to allow safe overpull in

case of a sticking problem, and well-control systems (e.g., ram preventers,

annular preventers, internal preventers) that allow kick control under any

kick situation are all necessary for reducing drilling problems and opti￾mization of ROP. Proper monitoring and recording systems that monitor

trend changes in all drilling parameters are very important to rig efficiency.

These systems can retrieve drilling data at a later date. Proper tubular hard￾ware specifically suited to accommodate all anticipated drilling conditions,

and effective mud-handling and maintenance equipment will ensure that

the mud properties are designed for their intended functions.

3. Formation Characteristics: The formation characteristics are some

of the most important parameters that influence the ROP. The following

formation characteristics affect the ROP: i) elasticity i.e., elastic limit, ii)

ultimate strength, iii) hardness and/or abrasiveness, iv) state of under￾ground formations stress, v) stickiness or balling tendency, vi) fluid con￾tent and interstitial pressure, and vii) porosity and permeability. Among

these parameters, the most important formation characteristics that affect

the ROP are the elastic limit and ultimate strength of the formation. The

shear strength predicted by the Mohr failure criteria sometimes is used to

characterize the strength of the formation.

The elastic limit and ultimate strength of the formation are the most

important formation properties affecting penetration rate. It is men￾tioned that the crater volume produced beneath a single tooth is inversely

proportional to both the compressive strength of the rock and the shear

strength of the rock. The permeability of the formation also has a signifi￾cant effect on the penetration rate. In permeable rocks, the drilling fluid

filtrate can move into the rock ahead of the bit and equalize the pressure

differential acting on the chips formed beneath each tooth. It can also be

argued that the nature of the fluid contained in the pore space of the rock

also affects this mechanism since more filtrate volume would be required

to equalize the pressure in a rock containing gas than in a rock contain￾ing liquid. The mineral composition of the rock also has some effect on

penetration rate.

To determine the shear strength from a single compression test, an aver￾age angle of internal friction varies from about 30 to 40° from the most

rock. The following model has been used for a standard compression test:

The threshold force or bit weight (W/d)

t

required to initiate drilling was

obtained by plotting drilling rate as a function of bit weight per bit diam￾eter and then extrapolating back to a zero drilling rate. The laboratory cor￾relation obtained in this manner is shown in Figure 2.17.

The other factors such as permeability of the formation have a signifi￾cant effect on the ROP. In permeable rocks, the drilling fluid filtrate can

move into the rock ahead of the bit and equalize the pressure differential

acting on the chips formed beneath each tooth. Formation as nearly an

independent or uncontrollable variable is influenced to a certain extent by

hydrostatic pressure. Laboratory experiments indicate that in some forma￾tions increased hydrostatic pressure increases the formation hardness or

reduces its drill-ability. The mineral composition of the rock also has some

effect on ROP. Rocks containing hard, abrasive minerals can cause rapid

dulling of the bit teeth. Rocks containing gummy clay minerals can cause

the bit to ball up and drill in a very inefficient manner.

4. Mechanical Factors: The mechanical factors are also sometimes

described as bit operating conditions. The following mechanical factors

affect the ROP: i) bit type, ii) rotary speed, and iii) weight on bit.

Bit Type: The bit type selection has a significant effect on rate of penetra￾tion. For rolling cutter bits, the initial penetration rates for shallow depths 

are often highest when using bits with long teeth and a large cone off set 

angle. However, these bits are practical only in soft formations because 

of rapid tooth wear and sudden decline in penetration rate in harder for￾mations. The lowest cost per foot drilled usually is obtained when using 

the longest tooth bit that will give a tooth life consistent with the bearing 

life at optimum bit operating conditions. The diamond and PDC bits are 

designed for a given penetration per revolution by the selection of the size 

and number of diamonds or PDC blanks. The width and number of cut￾ters can be used to compute the effective number of blades. The length of 

the cutters projecting from the face of the bit (less the bottom clearance) 

can limit the depth of the cut. The PDC bits perform best in soft, firm, and 

medium-hard, nonabrasive formations that are not gummy. Therefore, the 

bit type selection must be considered, i.e., whether a drag bit, diamond bit, 

or roller cutter bit must be used, and the various tooth structures affect to 

some extent the drilling rate obtainable in a given formation.

Figure 2.18 shows the characteristic shape of a typical plot of ROP vs. 

WOB obtained experimentally where all other drilling variables remain 

constant. No significant penetration rate is obtained until the threshold 

bit weight is exceeded (point a). ROP increases gradually and linearly with 

increasing values of bit weight for low-to-moderate values of bit weight 

(segment ab). A linear sharp increase curve is again observed at the high 

bit weight (segment bc). Although the ROP vs. WOB correlations for the 

discussed segments (ab and bc) are both positive, segment bc has a much 

steeper slope, representing increased drilling efficiency. Point b is the tran￾sition point where the rock failure mode changes from scraping or grinding 

to shearing. Beyond point c, subsequent increases in bit weight cause only 

slight improvements in ROP (segment cd). In some cases, a decrease in ROP 

is observed at extremely high values of bit weight (segment de). This type 

of behavior sometimes is called bit floundering (point d – bit floundering 

point). The poor response of ROP at high WOB values is usually attributed 

to less-efficient hole cleaning because of a higher rate of cuttings genera￾tion, or because of a complete penetration of a bit’s cutting elements into 

the formation being drilling, without room or clearance for fluid bypass.

ii) Rotary Speed: Figure 2.19 shows a characteristic shape typical response 

of ROP vs. rotary speed obtained experimentally where all other drilling 

variables remain constant. Penetration rate usually increases linearly with 

increasing values of rotary speed (N) at low values of rotary speed (seg￾ment ab). At higher values of rotary speed (after point b, segment b to c), 

the rate of increase in ROP diminishes. The poor response of penetration 

rate at high values of rotary speed usually is also attributed to less effi￾cient bottom-hole cleaning. Here, the bit floundering is due to less efficient 

bottom-hole cleaning of the drill cuttings.

Maurer (1962) developed a theoretical equation for rolling cutter bits 

relating ROP to bit weight, rotary speed, bit size, and rock strength. The 

equation was derived from the following observations made in single-insert 

iii) Weight on Bit: The significance of WOB can be shown as explained by 

Figure 2.18. The figure shows that no significant penetration rate is obtained 

until the threshold bit weight (Wt

) is applied (Segment oa, i.e., up to point 

a). The penetration rate then increases rapidly with increasing values of bit 

weight (Segment ab). Then a constant rate in increase (linear) in ROP is 

observed at moderate bit weight (Segment bc). Beyond this point (c), only 

a slight improvement in the ROP (segment cd) is observed. In some cases, a 

decrease in penetration rate is observed at extremely high values of bit weight 

(Segment de). This behavior is called bit floundering. It is due to less efficient 

bottom-hole cleaning (because the rate of cutting generation has increased).

5. Drilling Fluid Properties: The properties of the drilling fluid reported 

to affect the penetration rate include: i) density, ii) rheological flow prop￾erties, iii) filtration characteristics, iv) solids content and size distribution, 

and v) chemical composition. ROP tends to decrease with increasing fluid 

density, viscosity, and solids content. It tends to increase with increasing 

filtration rate. The density, solids content, and filtration characteristics of 

the mud control the pressure differential across the zone of crushed rock 

beneath the bit. The fluid viscosity controls the parasitic frictional losses 

in the drillstring and, thus, the hydraulic energy available at the bit jets 

for cleaning. There is also experimental evidence that increasing viscosity 

reduces penetration rate even when the bit is perfectly clean. The chemi￾cal composition of the fluid has an effect on penetration rate, such that 

the hydration rate and bit balling tendency of some clays are affected by 

the chemical composition of the fluid. An increase in drilling fluid den￾sity causes a decrease in penetration rate for rolling cutter bit. An increase 

in drilling fluid density causes an increase in the bottom hole pressure 

beneath the bit and, thus, an increase in the pressure differential between 

the borehole pressure and the formation fluid pressure.

6. Bit Tooth Wear: Most bits tend to drill slower as the drilling time elapses 

because of tooth wear. The tooth length of milled tooth rolling cutter bits 

is reduced continually by abrasion and chipping. The teeth are altered by

hard facing or by case-hardening process to promote a self-sharpening

type of tooth wear. However, while this tends to keep the tooth pointed, it

does not compensate for the reduced tooth length. The teeth of tungsten

carbide insert-type rolling cutter bits and PDC bits fail by breaking rather

than by abrasion. Often, the entire tooth is lost when breakage occurs.

Reductions in penetration rate due to bit wear usually are not as severe for

insert bits as for milled tooth bits unless a large number of teeth are broken

during the bit run.

7. Bit Hydraulics: Significant improvements in penetration rate could be

achieved by a proper jetting action at the bit. The improved jetting action

promoted better cleaning of the bit face as well as the hole bottom. There

exists an uncertainty on selection of the best proper hydraulic objective

function to be used in characterizing the effect of hydraulics on penetra￾tion rate. Bit hydraulic horsepower, jet impact force, Reynolds number,

etc., are commonly used objective functions for describing the influence of

bit hydraulics on ROP.

8. Directional and Horizontal Well Drilling: Since the 1980s, when the

horizontal well technology was ‘perfected’, the majority of the wells in the

developed world use horizontal wells. This is also accompanied by inclined

and directional wells that had already gained usefulness in offshore drill￾ing. Common field of applications for directional and horizontal drilling

are in offshore and onshore, where vertical wells are impractical to drill or

much higher return for investment is assured with horizontal wells. Over

the last three decades, there has been a major shift from vertical to hori￾zontal wells. The use of horizontal wells has allowed for greater formation

access. As more and more horizontal wells are drilled, the cost of hori￾zontal well drilling declines. As IEA report (2016) indicates, over the past

decades, lateral lengths have increased from 2,500 feet to nearly 7,000 feet

and, at the same time, we have seen nearly a threefold increase in drilling

rates (feet/day). This is shown in Figure 2.20. Even though such an increase

in efficiency in horizontal well has driven the drilling cost down, the tech￾nology has not caught on in the developing countries, where horizontal

wells are still deemed prohibitively expensive.

The major applications of directional drilling are to i) develop the fields

which are located under population centers, ii) drill wells where the reser￾voir is beneath a major natural obstruction, iii) sidetrack out of an exist￾ing well bore, and iv) elongate reservoir contact and thereby enhance well

productivity (Hossain and Al-Majed, 2015).

9. Improve ROP in Field Operations: Time spent to drill ahead is usually

a significant portion of total well cost. Rotating time usually accounts for

10% to 30% of well cost in typical wells. This means that the penetration rate

achieved by the drill bit has considerable impact on reduction on drilling

cost. A method has been developed to identify which factors are control￾ling ROP in a particular group of bit runs. The method uses foot-based mud

logging data, geological information, and drill bit characteristics to produce

numerical correlations between ROP and applied drilling parameters or

other attributes of drilling conditions. These correlations are then used to

generate recommendations for maximizing ROP in drilling operations. The

objective of this method is to quantify the effects of operationally control￾lable variables on ROP. To reveal the effects of these variables, data sets must

be constructed so as to minimize variation in environmental conditions. The

first step is therefore to select a group of bit runs made with the same bit

size through similar formations. Next, intervals of consistent lithology are

identified with a preference for formations exhibiting lateral homogeneity.

Formations such as shale and limestone are in general more suitable than

variable lithologies such as sandstone. Rock property logs can be used to ver￾ify comparability. Further sorting can be made depending on the objectives

of each specific analysis to separate bit runs in different mud types with dif￾ferent classes of bit or to separate intervals drilled with sharp bits versus those

in worn condition. Each step helps to further expose the effects on ROP of

bit design, and mechanical or hydraulic drilling parameters. Once intervals

have been selected and sorted, numerical averages of the variables of interest

are obtained. This is critical because many sources of error exist in drilling

parameter measurements, and improvement in data quality. Averaging to

raise sample size is the most obvious method to minimize the effects of error.

Figure 2.21 shows a log, for which data have been extracted and aver￾aged from an interval of shale early in the bit run, prior to a drop in ROP 

related to bit wear in a sandstone. This process would then be repeated 

for other bit runs made through the same stratigraphic interval, yielding a 

data set suitable for analysis. For example, BP Exploration customized pet￾rophysical software which is used to automate the extraction and averaging 

of drilling data though manual processing from paper logs. Once data are 

prepared, correlation analysis is performed in conventional spreadsheets. 

Cross plots are used to seek visible correlations between ROP and the inde￾pendent variables, and statistics functions are used to establish the degree 

of correlation and to build models for prediction of ROP.