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.