Introduction reservoir engineering 1

 Definition of a Reservoir

A petroleum reservoir is a porous and permeable subsurface pool or formation of

hydrocarbon that is contained in fractured rocks which are trapped by overlying

impermeable or low permeability rock formation (cap rock, that prevents the vertical

movement) and an effective seal (water barrier to prevent the lateral movement of the

hydrocarbon) by a single natural pressure system. Figure 1.1 shows clearly the

essential features of a reservoir which are: source rock, cap rock (non-permeable

rock), reservoir (porous and permeable rock) rock, hydrocarbon (oil and gas) and

aquifer (water sand).

Elements Required in the Definition of a Reservoir

The definition of a reservoir is not complete without mentioning the following: the

source rock, migration pathway, reservoir rock which talks about porosity and

permeability, cap rock, trap and a seal. These are briefly explained below.

1.2.1.1 Source Rock Hydrocarbon Generation

This is a rock in which hydrocarbon is generated from or has generated moveable

quantities of hydrocarbon. It is a site where hydrocarbon liquid is formed from an

organic-rich source rock with kerogen (Fig. 1.2, a precursor of petroleum) and

bitumen to accumulate as oil or gas or a combination of both oil and gas.

To characterize a rock as source rock, the following basic features need to be in

place:

• The quantity of organic matter which is commonly assessed by a measure of the

total organic carbon (TOC) contained in a rock.

• The quality which is measured by determining the types of kerogen contained in

the organic matter and prevalence of long-chain hydrocarbons.

• The thermal maturity; usually estimated by using data from pyrolysis analysis.

Therefore, hydrocarbon generation is a critical phase in the development of a

petroleum system which depends on three main factors:

• The presence of organic matter rich enough to yield hydrocarbons,

• Adequate temperature,

• And sufficient time to bring the source rock to maturity. On the contrary, pressure

of the system, the presence of bacteria and catalysts also affect the hydrocarbon

generation.

1.2.1.2 Migration

Usually, the sites where hydrocarbons are formed are not the same sites where they

are accumulated to form a reservoir. They must travel a long distance before they are

eventually trapped. Hence, migration can be defined as the movement of hydrocar￾bons from the source rock into the reservoir rocks. Hydrocarbon migration can be

classified further as primary and secondary. When the newly generated hydrocar￾bons move out of their source rock to the reservoir rock, it is termed primary

migration, also called expulsion. While the further movement of the hydrocarbon

within the reservoir or area of accumulation is called secondary migration as shown

in Fig. 1.3.

Accumulation

It is the quantity of hydrocarbon that has gradually gathered or defined as the phase

in the development of a petroleum system during which hydrocarbons migrate into

the porous and permeable rock formation (the reservoir) and remain trapped until

wells are drilled through to produce the accumulated hydrocarbons.

1.2.1.4 Porosity

This is the storage capacity of the rock to host the migrated hydrocarbon from the

source rock. It can be defined as the fraction of the bulk volume of the rock that is

void or open for fluid to be stored.

1.2.1.5 Seal/Cap Rock

Cap rock is a harder or more resistant rock type overlying a weaker or less resistant

rock type. It is an impermeable rock that acts as a barrier to further migration of

hydrocarbon liquids. The cap rock prevents vertical migration while seal prevents

lateral migration of the hydrocarbon. A capillary seal is formed when the capillary

pressure across the pore throats is greater than or equal to the buoyancy pressure of

the migrating hydrocarbons. They do not allow fluids to migrate through them until

their integrity is disrupted, causing them to leak. Sometimes the caps are not perfect

seals and petroleum escapes to the Earth’s surface as natural seepage, which can be

spotted by oily residue on the surface soil and rocks (geologic survey). Underwater

seeps can bubble up to the surface and leave an oily sheen.

1.2.1.6 Trap

This term is defined as a subsurface rock formation sealed by a relatively imperme￾able formation through which hydrocarbons will not migrate (Fig. 1.4). It is formed

only when the capillary forces of the sealing medium cannot be overcome by the

buoyant forces responsible for the vertical/upward movement of the hydrocarbon

through the permeable rock. There are several types of traps encountered, which can

be represented as single, parallel, sealing and non-seal.

Traps can be described as structural traps, which are formed in geologic structures

such as folds and faults. structural traps are formed chiefly as a result of changes in

the structure of the subsurface rock, which may be caused by compaction, tectonic,

gravitational processes or due to processes such as uplifting, folding and faulting,

culminating to the formation of anticlines, folds and salt domes. Majority of the

world’s petroleum reserves are found in structural traps. These are shown in Fig. 1.5.

The other type of trap is the stratigraphic traps which are formed as a result of

changes in rock type or pinch-outs, unconformities, or other sedimentary features

such as reefs or build-ups. It can also be seen as traps formed as a result of lateral and

vertical variations in the thickness, texture, porosity or lithology of the

reservoir rock.

1.2.1.7 Permeability

This is defined as the ease at which the reservoir fluid flows through the porous space

of the reservoir rock to the surface when penetrated by a well.

1.2.1.8 Reservoir

For the hydrocarbons that migrated from the source rock to accumulate, there must

exist a subsurface body of rock (reservoir rock) having sufficient porosity to host or

store the migrated hydrocarbons and also permeable enough to transmit the fluids

when penetrated by a well. Therefore, a reservoir is a porous and permeable

subsurface formation containing an accumulation of producible hydrocarbons (Oil

and/or Gas), characterized by a single natural pressure system that is confined by

impermeable rock and water barriers.

The reservoir rocks are mostly sedimentary in nature because they are more

porous than most igneous and metamorphic rocks. See details in understanding the

basis of rock and fluid properties textbook written by one of the same authors.

Prior to the formation of the hydrocarbon, the reservoir was actually filled with

water. This will lead us to the concept of drainage and imbibition processes

discussed below.

1.3 Drainage and Imbibition Process

1.3.1 Drainage/Desaturation Process

It is generally agreed that the pore spaces of reservoir rocks were originally filled

with water, as hydrocarbon is being formed from the source rock, it migrates or

moves into the reservoir, where it displaces the water and leave some fraction called

connate or irreducible water undisplaced. Hence, when the reservoir is discovered,

the pore spaces are filled with connate water and oil saturation respectively. If gas is

the displacing agent, then gas moves into the reservoir, displacing the oil.

This same history must be duplicated in the laboratory to eliminate the effects of

hysteresis. The laboratory procedure is performed by, saturation of the core with

brine or water, then displace the water to a residual or connate water saturation with

oil after which the oil in the core is displaced by gas. This flow process is called the

gas drive depletion process. In the gas drive depletion process, the nonwetting phase

fluid is continuously increasing with increase in saturation, and the wetting phase

fluid is continuously decreasing. Therefore, drainage process is a fluid flow process

in which the saturation of the nonwetting phase increases and also, the mobility

increases with the saturation of the nonwetting phase.

Examples of drainage process (Onyekonwu MO, lecture note):

• Hydrocarbon (oil or gas) filling the pore space and displacing the original water of

deposition in water-wet rock

• Water flooding an oil reservoir in which the reservoir is oil wet

• Gas injection in an oil or water wet oil reservoir

• Evolution of a secondary gas cap as reservoir pressure decreases

1.3.2 Imbibition/Resaturation Process

The imbibition process is performed in the laboratory by first saturating the core with

the water (wetting phase), then displacing the water to its irreducible (connate)

saturation by injection oil. This “drainage” procedure is designed to establish the

original fluid saturations that were found when the reservoir was discovered. The

wetting phase (water) is reintroduced into the core and the water (wetting phase) is

continuously increased. This is the imbibition process and is intended to produce the

relative permeability data needed for water drive or water flooding calculations.

Therefore imbibition process is a fluid flow process in which the saturation of the

wetting phase increases and also, the mobility increases with the saturation of the

wetting phase.

Examples of imbibition process (Onyekonwu MO, lecture note):

• Accumulation of oil in an oil-wet reservoir

• Water flooding an oil reservoir in which the reservoir is water wet

• Accumulation of condensate as pressure decreases in a dew point

reservoir Figure 1.6 schematically illustrates the difference in the drainage

and imbibition processes of measuring relative permeability. It is noted that the

imbibition technique causes the nonwetting phase (oil) to lose its mobility at

higher values of water saturation than the drainage process does. The two

processes have similar effects on the wetting phase (water) curve. The drainage

method causes the wetting phase to lose its mobility at higher values of

nonwetting-phase saturation than does the imbibition method.

1.4 Reservoir Engineering

It is a branch of petroleum engineering that applies scientific principles to the

drainage problems arising during the development and production of oil and gas

reservoirs to obtain a high economic recovery. The reservoir engineer is saddled with

the responsibility like that of a medical doctor to make sure the reservoir does not go

below its expected performance (fall sick) and even if it falls sick; he/she looks for a

Role or Job Description of Reservoir Engineers

Since it is usually not possible to physically ascertain what is under the ground

because nobody goes into the reservoir, it implies that a Reservoir Engineer needs

some techniques to adequately establish what is inside the reservoir. Therefore, it is

the role of a reservoir engineer to continuously monitor the reservoir, collect relevant

data and interpret these data to be able to determine the past and present conditions of

the reservoir, estimate future conditions and control the flow of fluids through the

reservoir rock with an aim to effectively increase recovery factor and accelerate oil

recovery. It is worthy to note that the complete role/job description of a reservoir

engineer to a company differs considerably from other companies, but there are key

functions that are common to all. Some of the jobs description of a reservoir engineer

but are not limited are stated below:

• Estimation of the original hydrocarbon in place (OHCIP)

• Calculation of the hydrocarbon recovery factor, and

• Attachment of a time scale to the hydrocarbon recovery

Good experience in constructing numerical reservoir simulation models (black￾oil and compositional), model initialization, history matching, running sensitiv￾ities and predictions.

• Determination of reservoirs, field development strategy, production rates, reser￾voir monitoring plan, and economic life.

• Involvement of work with an integrated team of geologists, geophysicists,

petrophysicists, and engineers from other disciplines.

• Knowledge of PVT data analysis.

• Collecting, analyzing, validating, and managing data related to the project

• Carrying out reservoir simulation studies, either for facts finding or to optimize

hydrocarbon recoveries.

• Predicting reserves and performance from well proposals.

• Predicting and evaluating gas injection/waterflood and enhanced recovery

performance.

• Developing and applying reservoir optimization techniques.

• Developing cost-effective reservoir monitoring and surveillance programs.

• Performing reservoir characterization studies.

• Analyzing pressure transients.

• Designing and coordinating petrophysical studies.

• Analyzing the economics and risk assessments of major development programs.

• Estimating reserves for producing properties

Stimulation execution

Stimulation execution

A good understanding of job execution is necessary for making decisions on the applicability
and risk of various treatments. As with any well work, basic safety procedures must be
developed and followed to prevent catastrophic failure of the treatment, which could result
in damage to or loss of the well, personnel and equipment. Specific standards and
operating procedures have been developed for stimulation treatments, which if followed
can lead to a safe, smooth and predictable operation.
Matrix stimulation
Matrix stimulation, mainly acidizing, is the original and simplest stimulation treatment.
More than 40,000 acid treatments are pumped each year in oil and gas wells. These
treatments (Fig. 1) typically involve small crews and minimal equipment. The
equipment usually consists of one low-horsepower, single-action reciprocating pump, a
supply centrifugal and storage tanks for the acid and flush fluids.
Blending equipment is used when solids are added to the treatment.
The most common process is for the fluids to be preblended at the service company facility
and then transported to the location. This allows blending small volumes accurately,
controlling environmental hazards. The fluids are then pumped with little effort
or quality risk.
Hydraulic fracturing
Unlike matrix stimulation, fracturing can be one of the more complex procedures performed
on a well (Fig. 2). This is due in part to the high rates and

Figure 1 Matrix stimulation treatment using a coiled tubing unit, pump truck and
fluid transport.

Figure 2 This large fracturing treatment used 25,000 hydraulic horsepower and 1.54 million gal of fracturing fluid to place 6.3 million lbm of propping agent. The job
11 hours.


pressures, large volume of materials injected, continuous blending of materials and large
amount of unknown variables for sound engineering design. The fracturing pressure is
generated by singleaction reciprocating pumping units that have between 700 and 2000
hydraulic horsepower (Fig. 3). These units are powered by diesel, turbine or
electric engines. The pumps are purpose-built and have not only horsepower limits but job
specification limits. These limits are normally known (e.g., smaller plungers provide a higher
working pressure and lower rates). Because of the erosive nature of the materials (i.e.,
proppant) high pump efficiency must be maintained or pump failure may occur. The limits
are typically met when using high fluid velocities and high proppant concentrations (+18
ppg). There may be numerous pumps on a job, depending on the design. Mixing equipment
blends the fracturing fluid system, adds the proppant and supplies this mixture to the high-
pressure pumps. The slurry can be continuously mixed by the equipment (Fig. 4) or batch
mixed in the fluid storage tanks. The batch-mixed fluid is then blended with proppant in a
continuous stream and fed to the pumps.

RST ( Reservoir Saturation Tool )

RST

Applications

• Monitor water saturation
through tubing
• Locate by-passed oil
• Detect water flood fronts
• Fine-tune formation evaluation
through casing
• Evaluate wells lacking
open hole logs
• Monitor production profiles
• Monitor water saturation
through tubing
• Locate by-passed oil
• Detect water flood fronts
• Fine-tune formation evaluation
through casing
• Evaluate wells lacking
open hole logs
• Monitor production profiles

RST hardware

MINITRON
GENERATES EXTREMELY
POWERUL NEUTRONS WHEN
POWERD UP (14 MeV)
• MINITRON POWER UP ONLY
WHEN TOOL IS 150 FT.
BELOW SURFACE

Neutron
Interactions

RST Modes of Operation

Sigma Mode
OUTPUTS
•FOMATIOIN SIGMA FOMATIOIN SIGMA
•BOREHOLE SIGMA BOREHOLE SIGMA
•BOREHOLE SALINITY BOREHOLE SALINITY
•POROSITY POROSITY
•The ability of an atom to capture
neutron is called sigma Σ
• Chlorine present in saline water has
high Σ (Hydrocarbon does not have
any chlorine)

To be continued

PETROPHYSICS Lesson (1)

INTRODUCTION

Petrophysics is the study of rock properties and their interactions 
with fluids (gases, liquid hydrocarbons and aqueous solutions). Because 
petroleum reservoir rocks must have porosity and permeability, we are 
most interested in the properties of porous and permeable rocks. The 
purpose of this text is to provide a basic understanding of the physical 
properties of permeable geologic rocks and the interactions of the various 
fluids with their interstitial surfaces. Particular emphasis is placed on 
the transport properties of the rocks for single phase and multiphase 
flow. 
 The petrophysical properties that are discussed in this text 
include: 
• Porosity 
• Absolute permeability 
• Effective and relative permeabilities 

• Water saturation
Irreducible water saturation 
• Hydrocarbon saturation 
• Residual oil saturation 
• Capillary pressure 
• Wettability 
• Pore size 
• Pore size distribution 
• Pore structure 
• Net pay thickness 
• Isothermal coefficient of compressibility 
• Mineralogy 
• Specific pore surface area 

• Dispersivity

PETROLEUM RESERVOIR ROCKS

A petroleum reservoir rock is a porous medium that is sufficiently 
permeable to permit fluid flow through it. In the presence of 
interconnected fluid phases of different density and viscosity, such as 
water and hydrocarbons, the movement of the fluids is influenced by 
gravity and capillary forces. The fluids separate, therefore, in order of 
density when flow through a permeable stratum is arrested by a zone of 
low permeability, and, in time, a petroleum reservoir is formed in such a 
trap. Porosity and permeability are two fundamental petrophysical 
properties of petroleum reservoir rocks. 


Geologically, a petroleum reservoir is a complex of porous and 
permeable rock that contains an accumulation of hydrocarbons under a 
set of geological conditions that prevent escape by gravitational and 
capillary forces. The initial fluid distribution in the reservoir rock, which 
is determined by the balance of gravitational and capillary forces, is of 
significant interest at the time of discovery. 
 A rock capable of producing oil, gas and water is called a reservoir 
rock. In general, to be of commercial value, a reservoir rock must have 
sufficient thickness, areal extent and pore space to contain a large 
volume of hydrocarbons and must yield the contained fluids at a 
satisfactory rate when the reservoir is penetrated by a well. Any buried 
rock, be it sedimentary, igneous or metamorphic, that meets these 
conditions may be used as a reservoir rock by migrating hydrocarbons. 
However, most reservoir rocks are sedimentary rocks. 
 Sandstones and carbonates (limestones and dolomites) are the 
most common reservoir rocks. They contain most of the world’s 
petroleum reserves in about equal proportions even though carbonates 
make up only about 25% of sedimentary rocks. The reservoir character 
of a rock may be primary such as the intergranular porosity of a 
sandstone, or secondary, resulting from chemical or physical changes 
such as dolomitization, solution and fracturing. Shales frequently form 
the impermeable cap rocks for petroleum traps. 
 The distribution of reservoirs and the trend of pore space are the 
end product of numerous natural processes, some depositional and some 
post-depositional. Their prediction, and the explanation and prediction of 
their performance involve the recognition of the genesis of the ancient 
sediments, the interpretation of which depends upon an understanding 

of sedimentary and diagenetic processes. Diagenesis is the process ofphysical and chemical changes in sediments after deposition that convert 
them to consolidated rock such as compaction, cementation, 
recrystallization and perhaps replacement as in the development of 
dolomite.

 MINERAL CONSTITUENTS OF ROCKS - A REVIEW

The physical and chemical properties of rocks are the consequence 
of their mineral composition. A mineral is a naturally occurring 
crystalline inorganic material that has specific physical and chemical 
properties, which are either constant or vary within certain limits. Rock-
forming minerals of interest in petroleum engineering can be classified 
into the following families: silicates, carbonates, oxides, sulfates 
(sulphates), sulfides (sulphides) and chorides. These are summarized in 
Table 1.1. Silicates are the most abundant rock-forming minerals in the 

Earth’s crust. 

ROCKS

A rock is an aggregate of one or more minerals. There are three
classes of rocks: igneous, metamorphic and sedimentary rocks .

 Igneous Rocks

 These are rocks formed from molten material (called magma) that
solidified upon cooling either:
1. At the earth’s surface to form volcanic or extrusive rocks, e.g.,
basaltic lava flows, volcanic glass and volcanic ash.
or
2. Below the surface, usually at great depths, to form plutonic or
intrusive rocks, e.g., granites and gabbros.
 Igneous rocks are the most abundant rocks on the earth’s crust,
 making up about 64.7% of the Earth’s crust

Metamorphic Rocks

 These are rocks formed by transformation, generally in the solid
state, of pre-existing rocks beneath the surface by heat, pressure and
chemically active fluids, e.g., quartz is transformed to quartzite and
limestone plus quartz plus heat gives marble and carbon dioxide.
 Metamorphic rocks are the second most abundant rocks on the
earth’s crust, making up 27.4% of the Earth’s crust.

Sedimentary Rocks

 These are rocks formed at the surface of the earth either by
1. Accumulation and consolidation of minerals, rocks and/or
organisms and vegetation, e.g., sandstone and limestone.
or
2. Precipitation from solution such as sea water or surface water,
e.g., salt and limestone.
 Sedimentary rocks are the source of petroleum and provide the
reservoir rock and trap to hold the petroleum in the earth’s crust.
Sedimentary rocks are the least abundant rocks on the earth’s crust,
making up about 7.9% of the earth’s crust. Because most reservoir
rocks are sedimentary rocks, they are of particular interest to us in the
study of petrophysics. Therefore, we will examine sedimentary rocks in
more detail than igneous and metamorphic rocks.

Pressure Transient Analysis in Drawdown and Buildup lesson (1)

Pressure Transient Analysis

in Drawdown and Buildup

Dual flow Dual shat shat in test

Exploration Well Test Objectives

1. Determine the nature of the formation fluids

2. Measure the well productivity

3. Measure temperature and pressure

4. Obtain samples for lab analysis

Exploration Well Test Objectives

5. Obtain information for reservoir description

 (permeability , heterogeneity)

6. Estimate completion efficiency

Dual Flow - Dual Shut in Test

Initial flow and shutin designed to establish

communication with the reservoir

Initial flow as short as possible

Major flow period long enough to give

sufficient depth of investigation

Dual Flow - Dual Shutin Test

Often 6 - 12 hours is adequate

At least six hours of stable operation to

ensure reasonable estimate of productivity

and good samples

Multirate necessary in gas wells

Major shutin 1 - 2 times the duration of

the flow period

Methods of Gaining Information on Reservoir Characteristics

A. Seismic and associated geological studies

B. Information obtained during the well drilling program

C. Wireline formation testing

 1. Virgin Reservoir (Exploration and Appraisal Wells)

Methods of Gaining Information on Reservoir Characteristics

 2. Produced Reservoir (New development wells)

D. Pressure - Flow testing of wells

 1. Exploration and appraisal wells (DST)

 2. Production or injection wells

E. Analysis of reservoir performance

 - simulator history matching

Principal Objectives of Well Testing

Determine the average permeability of the reservoir

Determine the near wellbore alteration i.e. the skin factor

Measure the reservoir pressure

Attempt to locate the position of boundaries / discontinuities

Types of Pressure Transient Test

Principal Objectives of Well Testing

Pressure Drawdown (Reservoir Limit) Test

Pressure Bu ildup or Fa lloff Test

 - Drill Stem Te st (Downhole valve)

 - Production or Injectio n Well Test

In terference Test

Pulse Test - horizontal or vertical

Transient Well Testing

Buildup Analysis - Horner (Theis) Plot

From Steady-State Radial Flow TheoryNear Wellbore Altered Zone

Hawkins Equation - Open-Hole

From Steady-State Radial Flow Theory

Well Productivity

The well P.I. depends mainly on:

Permeability - Thickness Product

Oil Viscosity

Overall Skin Factor

 Drainage radius

 Wellbore radius

 Formation volume factor

are of secondary importance

Well Productivity Index, Jsss

Determination of Average Pressure

Flow Regimes

Detection of Depletion

Some Well Test Models

Homogeneous Finite

Composite Infinite

Reservoir

No Flow

Boundary

Composite Infinite

Reservoir

No flow boundary

Single Linear Fault

Model Reservoir

Assumptions

Well completed over entire thickness of formation

Homogeneous and isotropic porous medium

Uniform formation thickness

Bounded above and below by impermeable barrier

s

Porosity and permeability constant

Assumptions

Lead to Radial 1-D Flow

Formation contains a single phase liquid with constant viscosity

and small and constant compressibility

Leads to Diffusivity Equation

Nomenclature

k Permeability of porous medium

 Porosity of porous medium

 Fluid viscosity Fluid density

c Fluid compressibility h Formation thickness

φ

µ

ρ

p Pressure t Time

Nomenclature

r Wellbore radius

q Oil flow-rate (stock tank conditions)

B Formation volume factor r External radius

r Radial coordinate p Initial pressure

 Hydraulic diffusivity

To be continued 

FISHING ECONOMICS

 FISHING ECONOMICS

The option of abandoning fishing operations and sidetracking the well should be taken on
economic grounds unless there are exceptional logistical, legislative or safety grounds.
Before giving up on a fishing job the cost of sidetracking operations together with re-drilling
to the original depth needs to be calculated. This cost when converted to equivalent rig day
rate days can be used to assess the amount of time that it is economic to pursue fishing
operations. The procedure is as follows:
a. Calculate the total cost of the fish to be left in hole.
b. Calculate the cost of backing-off and setting of a cement plug prior to sidetracking. This
should include all rental and consumable items, including personnel.
c. Calculate the cost of the sidetrack including directional equipment and casing milling
equipment (if applicable).
d. Calculate the cost of drilling to the original depth. This should be based on the time to drill
the original section plus an additional 10% to account for the directional aspects.
Total cost is therefore = a + b + c + d.
This should be converted to rig days by dividing the total cost by the rig day rate.
Abandonment of fishing operations should be considered when the fishing time has reached
½ the above number of days, and the probability of completing the fishing operation is
gradually becoming small.

Hole Problems Lec ( 3 )

MECHANICAL STICKING 

CAUSES OF MECHANICAL STICKING
In mechanical sticking the pipe is usually completely stuck with little or no circulation. In
differential sticking, the pipe is completely stuck but there is full circulation.Mechanical
sticking can occur as result of the hole packing off (or bridging) or due to formation & BHA
(wellbore geometry).
Hole pack off (bridging) can be caused by any one or a combination of the following
processes:
1. Settled cuttings due to inadequate hole cleaning
2. Shale instability
3. Unconsolidated formations
4. Fractured and faulted formations
5. Cement blocks
6. Junk falling in the well
The formation & BHA (wellbore geometry) can also cause mechanical sticking as follows:
1. Key seating
2. Mobile formations
3. Undergauge hole
4. Ledges and micro doglegs
Understanding the cause of the mechanical sticking problem is key to solving the problem.
This is because the cause determines the action required to free the pipe. For example, if the
pipe becomes stuck while running in an open hole, it is likely that the BHA has hit a ledge or
gone into an undergauge hole. In other words, the sticking problem is due to the geometry of
the wellbore. As will be seen later, the freeing action depends largely on identifying and
curing the problem that caused mechanical sticking.
A discussion of each of the above processes will now follow.

HOLE PACK OFF CAUSES

1- SETTLED CUTTINGS
Settled cuttings due to inadequate hole cleaning (Figure 12.4) is one of the major causes of
stuck pipe. Best hole cleaning occurs around large OD pipe such as drillcollars, while
cuttings beds can form higher up the hole where the pipe OD is smaller. The problem of
settled cuttings is particularly severe in horizontal and high directional wells. In these wells,
when the pipe is moved upwards, the cuttings may be compacted around the BHA. This can
result in complete packing off of the drillstring and eventual pipe sticking.
With increasing deviation of the wellbore, drilling fluid parameters, drilling practices and
hydraulics should be optimised in order to effectively clean the hole.

In vertical wells, good hole cleaning is
achieved by the selection and
maintenance of suitable mud parameters
and ensuring that the circulation rate
selected results in an annular velocity
(around 100-120 ft/min) which is greater
than the slip velocity of the cuttings.
Highly inclined wells are particularly
difficult to clean due to the tendency of
drilled cuttings to fall to the low side of
the hole.In a highly deviated well, the
cuttings have only a small distance to fall
before they settle on the low side of the
hole and form a cuttings bed. Cuttings
beds develop in boreholes with
inclinations of 30 degrees or greater, depending on the flow rates and suspension properties
of the drilling fluid.Complete removal of cuttings beds by circulation may be impossible.
Once cuttings beds have formed, there is always a risk that on pulling the pipe up the hole,
the cuttings are dragged from the low side of the hole forming a cuttings pile (Figure 12.4).
If this pile accumulates around the BHA, it may plug the hole and cause the pipe to
mechanically stuck.
Besides causing stuck pipe, settled cuttings can result in:
• formation break down due to increased ECD
• slow ROP
• excessive overpull on trips
• increased torque
Hole cleaning is controlled by a number of parameters which were discussed in Chapter 8.
These include:
1. mud rheology, in particular the YP and gel strength
2. flow rate
3. hole angle
4. mud weight
5. ROP
6. hole diameter
7. drillpipe rotation
8. presence of wash outs

2 - SHALE INSTABILITY
Shale represents 70% of the rocks encountered whilst drilling oil and gas wells. Also shale
instability is by far the most common type of wellbore instability. Shales are classified as
being either brittle or swelling.
Brittle Shales
Instability in brittle shales is caused
mainly by tangential stresses around the
wellbore which are induced as a result of
the well being drilled. The induced
stresses depend on the magnitude of the
in-situ stresses, wellbore pressure, rock
strength and hole angle and direction.
Formation dip may also be a
contributory factor to brittle shale
failure. A safe mud envelope may be
established which can be used to
determine the safe mud weights to
prevent either tensile failure or collpase (compressive) failure.
Brittle shales tend to fail by breaking into pieces and sloughing into the hole. Rig indications
of brittle shale failure include:
• large amounts of angular, splintery cavings when circulating the well
• drag on trips

• large amounts of hole fill.

3 - Swelling Shales
Shales swelling (Figure 12.6) can be caused by hydrational processes or by the osmotic
potential which develops between the pore fluid of the shale and drilling fluid salinity.
The swelling of shales (Figure 12.6) is controlled by several complex factors including:
• Clay content
• Type of clay minerals (ie hydratable or inert)
• Pore water content and composition
• Porosity
• In-situ stresses
• Temperature
The degree of clay hydration depends on
the clay type and the cation exchange
capacity (CEC) of the clay content. The
greater the CEC, the more hydratable is the
clay. In drilling operations the following
clay types are encountered:
• Smectite with CEC of 80-150
meq/100g. Most of the
hydratable shales (termed
gumbos) belong to this group.
Bentonite clays belong to the
smectite group.
• Illite with CEC of 10-40 meq/100g.
• Chlorite with CEC of 10-40 meq/100g.
• Kaolinite with CEC of 3-10 meq/100g.

To aid the understanding of shale swelling, the following points must be considered:
1. The permeability of shales is very low, typically in the range of 10 -9 to 10 -6 Darcy.
(1 md = 10 –13 m2)
2. Thus, filter cakes do not form on shale surfaces.
3. However, water can still migrate into the shale (helped by the mud overbalance).
4. Water infusion into the shale will allow chemical effects to start working inside the
shale and at the exposed surfaces of the wellbore.
5. The pore pressure inside the shale section will also increase, contributing to destabilisation.
6. The low permeability of shale means that swelling effects can take considerable
time and shale instability can be a delayed effect.
Water can flow into or out of the shale through several processes; the most important ones
are hydrational and osmotic forces:
1. Hydration: This is by far the most common cause of shale hydration where water
flows into the shale and hydrate the clay plates. Highly hydratable shales are
composed of predominantly smectite- based clays. These clays (e.g.
montmorillonite) absorb water into the inner-layer space due to the high negative
charge on the surface of the clay platelet. This process results in the expansion of
the clay to several times its original volume.
Hydratable shales are usually found near the surface ±7000
At grater depths, the process of diagenesis converts the clay minerals into more stable forms, However, hydratable shales have been found in some wells at depths
greater than 7000 ft due to the inhibition of the diagenetic processes.
2. Chemical osmosis: This type of flow occurs at semi-permeable membranes which
are permeable to water and impermeable to solute ions or molecules. Shale surface
acts as a semi-permeable membrane allowing water to flow into or out of the shale
depending on the solute concentration of the mud and pore water of the shale. Water
flows through the semi-impermeable membrane from the low concentration to high
concentration solution. In terms of chemical jargon, water flows from solutions of
high water activity to solutions of low water activity until the concentrations of the
two solutions are equalised. (Water activity (aw): ratio of vapour pressure of water
in a solution, drilling mud or shale pore water to the vapour pressure of pure water
at the same temperature.)
3. Chemical diffusion: This is caused by the flow of solutes (soluble solids) from
areas of high concentration to low concentration. Hence if the concentration of
certain ions or molecules in the drilling mud is greater than those in the formation
water of the shale then the solute will flow into the formation provided there are no
barriers to flow. Solutes can also flow out of the shale if their concentration is
greater than that in the drilling mud. No flow will occur if solute concentration is the
same in mud and shale.
4. Hydraulic diffusion; water flows in the direction of decreasing hydraulic pressure
gradient (Darcy’s Law). This flow can only occur if the rock has permeability.
Shale hydration – Rig Site Indications 
• Soft, hydrated or mushy cuttings
• Clay balls in the flowline
• torque and drag fluctuations
• Shale shaker screens blind off
• Increase in LGS, filter cake thickness, PV, YP and MBT (Methlyene blue test)
• Increase or fluctuations in pump pressure
• Circulation is restricted or sometimes impossible
• Bit and stabiliser balling when POH
• Generally occurs while POH (Tight hole) and problems while logging
• Problems increase with time.

Shale hydration – Prevention and Cure
• Use Inhibited mud system or displace to OBM system if possible
• Maintain mud properties as planned
• Addition of various salts (potassium, sodium, calcium) will reduce chemical
attraction between shale & water
• Addition of encapsulating polymers to WBM
• Reduce exposure time and case off the hydrated shale as soon as possible
• Regular wiper trips
• Good hole cleaning (especially in extended reach wells, ERW)

3 - UNCONSOLIDATED FORMATIONS
Unconsolidated formations are usually encountered
near the surface and include: loose sands, gravel and
silts. Unconsolidated formations have low cohesive
strengths and will therefore collapse easily (Figure
12.7) and flow into the wellbore in lumps and pack off
the drillstring.
Surface rig indications of an impending stuck pipe
situation near top hole are: increasing torque, drag and
pump pressure while drilling. Other signs include
increased ROP and large fill on bottom.
A common remedial action is to use a mud system with
an impermeable filter cake to reduce fluid invasion into
the rock. Reduction of flow rate, and in turn annular velocity, will reduce erosion of the hole
and removal of the filter cake.

4 - FRACTURED AND FAULTED FORMATIONS
This is a common problem in limestone and chalk formations. Several symptoms can be
observed on surface including:
• large and irregular rock fragments on shakers
• increased torque, drag and ROP
• small lost circulation
These fractured and faulted formations may fall into the Wellbore as soon as they are drilled
as the stresses which originally held them together are relieved by the drilling of the hole. In
addition, excessive drillstring vibrations cause the pipe to whip downhole and break and
dislodge the exposed fractured/faulted rocks. Therefore it is important to reduce drillstring
whipping to prevent dislodging of rock fragments when drilling fractured and faulted rocks.
In all cases, it is imperative to keep the hole clean in order to reduce the chances of hole
packing off.
If the drillstring is stuck in limestone or chalk formations and cannot be freed by jarring, an
inhibited hydrochloric acid pill may be spotted around the stuck zone.The acid will react
with the chalk/limestones, dissolving the rock around the pipe.If the pill is successful the
pipe will be freed quickly.

5 - CEMENT BLOCKS
Stuck pipe can be caused by cement blocks falling from the rat hole beneath the casing shoe
or from cement plugs.
This problem may be prevented by minimising the rat hole to a maximum of 5 ft and also by
ensuring a good tail cement is placed around the shoe .
The drillstring can also be stuck in green cement which has not set properly. This usually
occurs after setting a cement plug inside the casing or open hole. If the drillstring is run too
fast into the top of the cement and if the cement is still green then the cement can flash set
around the pipe and cause the pipe to be permanently stuck.

The author has come across several situations where the top of the cement is soft when
tagged, but literally within seconds of tagging the cement, the cement flash sets around the
BHA causing mechanical sticking. One possible explanation for this sudden flash setting is
that the energy release while circulating and rotating is enough to cause flash setting. It is
recommended that circulation is started two to three stands above the expected top of cement
and that WOB should be kept to absolute minimum.

6 - JUNK
Several recorded incidents of pipe sticking occurred as a result of junk falling into the hole.
This include junk falling into the wellbore from the surface or from upper parts of the hole.
Typical junks dropped from surface include pipe wrenches, spanners, broken metal, hard
hats etc. This problem can be minimised by keeping the hole covered when no tools are run
in the hole.
Junks can also fall from within the well including broken packer elements, liner hanger slips
and metal swarf from milling operation.

HOLE PROBLEMS lec ( 2 )

DIFFERENTIAL STICKING FORCE

The differential sticking force is given by:
Differential sticking force (DSF) = (Hs - Pf) x effective contact area x friction factor (12.1)
whereHs = hydrostatic pressure of mud
Pf = formation pressure
In Equation (12.1), the most difficult terms to determine are the effective contact area and
the friction factor between the mud cake and the pipe steel. To a first approximation the

effective area may be calculated as the product of the height of the exposed permeable
formation times 20% of the perimeter of the drillpipe or drillcollars.
Another equation for estimating the contact area is given by

It should observed that none of the equations given for estimating the contact area are
completely valid as the contact area is affected by a number of variables including the
friction factor (time-dependent), the amount of bend in the drillpipe or collars, hole angle
and thickness of the filter cake.
The surface estimate of the thickness of the filter cake can be very different from that
occurring downhole.

Example : Differential Sticking Force
Determine the magnitude of the differential sticking force across a permeable zone of 30 ft
in thickness using the following data:
Differential pressure = 500 psi
Area of contact is 20% of effective drillpipe perimeter
Filter cake = 1/2 in (12.7mm); friction factor = 0.1.
Drillpipe OD: 5"
Solution
Perimeter of drillpipe = π x OD = π x 5 = 15.71 in
DSF = (Hs - Pf) x h x 20% x 15.71
= 500psi x (30ft x 12 in) x 20% x 15.71
= 565,560 lb

FREEING DIFFERENTIALLY STUCK PIPE .

There are basically two ways in which a differentially stuck pipe can be released:
• reduction of hydrostatic pressure
• spotting pipe release agents

 REDUCTION OF HYDROSTATIC PRESSURE 

The reduction of hydrostatic pressure is the obvious and most successful method of freeing a differentially stuck pipe. The lowering of the hydrostatic pressure reduces the side loading
forces on the pipe and therefore reduces the force required to free the pipe from the filter
cake. There are several methods by which this may be achieved. However prior to
implementing this action the following factors should be seriously considered:
1. Are there other pressured zones in the open hole section?
2. Will these exposed zones kick if the hydrostatic pressure is reduced?
3. The confidence level in the accuracy of pore pressure estimates made while drilling
and the pressure control equipment.
4. The effects of a reduction in hydrostatic pressure on the mechanical stability of all
exposed formations.
5. The volumes of base oil or water required to achieve the required reduction in
hydrostatic pressure. (This may well influence the method chosen).
All the above factors need to be carefully considered prior to reducing the hydrostatic
pressure as the potential for inducing a well control problem or formation instability are
considerably increased. The following methods for reducing hydrostatic pressure can be
used:
• circulation & reducing mud weight
• displacing the choke
• the ‘U’ tube method

CIRCULATION & REDUCING MUD WEIGHT

In this method, the drilling mud is circulated and its weight is gradually reduced. The
minimum mud weight required to balance the highest pore pressure in open hole should be
determined and the mud weight cut back in small stages. Close attention must be made to all
kick indicators whilst circulating down (reducing) the mud weight, frequent flow checks
should also be made. Whilst reducing the mud weight, tension should be held on the pipe.

Disadvantages of this methods are:
• It is slow, and remember the force required to free pipe is time dependent.
• The volume increase required may overload the surface pit handling capability.
This may be a serious problem when OBM is used.
• The active volume will be increasing during the reduction in mud weight,
making kick detection difficult.

DISPLACING THE CHOKE

This method is applicable to floating rigs where BOPS are placed on the seabed. The
hydrostatic pressure can be quickly and effectively reduced by displacing the choke line to
base oil or water. The well is shut in using the annular preventer and the displaced choke line
opened thereby reducing the overbalance.Note that the annular preventer isolates the
wellbore from the hydrostatic head of mud in the riser from rig floor to the annular preventer.
The advantage of this method is that if any influx is taken, the well can be immediately
killed by closing the choke and opening the annular. This action again exposes the well to the
active hydrostatic pressure from rig floor to TD. The disadvantage of this method is that the
amount of reduction in hydrostatic pressure is limited to the water depth. This may well
result in a limited reduction in shallow water, or in the case of deep water, an excessive
reduction in hydrostatic pressure

THE ‘U’ TUBE METHOD

The U-tube method is used to reduce the hydrostatic pressure of mud to a level equal or
slightly higher than the formation pressure of the zone across which the pipe got
differentially stuck.Clearly, the objective is to free the differentially stuck pipe safely without
losing control of the well by inadvertently inducing underbalanced conditions. A pipe free
agent should be spotted across the permeable zone prior to adopting the ‘U’ tube method.
The mathematics required for the full method is laborious, however,

SPOTTING PIPE RELEASE AGENTS

The severity of differentially stuck pipe can be reduced by the spotting of pipe release
agents. Pipe release agents are basically a blend of surfactants and emulsifiers mixed with
base oil or diesel oil and water to form a stable emulsion. They function by penetrating the
filter cake, therefore making it easier to remove and at the same time, reduce the surface
tension between the pipe and the filter cake.
Due to the time dependency of the severity of differential sticking, the pipe release agent
should be spotted as soon as possible after differential sticking is diagnosed. Typically the
pill will be prepared whilst initially attempting to mechanically free the pipe; ie by pulling
and rotating.

Example : Reduction of Hydrostatic Pressure
Calculate the volume of oil required to reduce the hydrostatic pressure in a well by 500 psi,
using the following data:
mud weight = 10 ppg
hole depth = 9,843 ft
drillpipe = OD/ID = 5 in/4.276 in
hole size = 12.25 in
specific gravity oil = 0.8 (6.7 ppg)
Solution
Initial hydrostatic pressure = 0.052 x10x 9843 = 5,118 psi
Required hydrostatic pressure = 5,118 - 500 = 4,618 psi
Thus,
New hydrostatic pressure = pressure due to (mud and oil) in drillpipe
4618 = 0.052x 10xY (mud) +0.052x (6.7) x (9843-Y) (oil)

where Y = height of mud in drillpipe.
Therefore,Y = 6,927 ft
Hence,
height of oil = 9,843 - 6,927 = 2,916 ft
volume of oil = capacity of drillpipe x height
= 290.79 ft3
= 51.7 bbl
Note that when the required volume of diesel oil is pumped inside the drillpipe, the
hydrostatic pressure at the drillpipe shoe becomes 4,618 psi, while the hydrostatic pressure
in the annulus is still 5,118 psi. This difference in the pressure of the two limbs of the well
causes a back-pressure on the drillpipe which is the driving force for removing the diesel oil
from the drillpipe and reducing the level of mud in the annulus. It is only when the annulus
level decreases that the hydrostatic pressure against the formation is reduced and the stuck
pipe may be freed.
When the formation pressure is unknown, it is customary to reduce the hydrostatic pressure
of mud in small increments by the U-tube technique until the pipe is free.
A variation of the U-tube method is to pump water into both the annulus and the drillpipe to
reduce hydrostatic pressure to a value equal to or just greater than the formation pressure.
This method is best illustrated by an example.

Example : : Simplified U-Tube Method
The following data refer to a differentially stuck pipe at 11,400 ft:
Formation pressure = 5,840 psi
Intermediate casing = 9.625 in, 40# at 10,600 ft
Drillpipe = OD /ID = 5/4.276 in

Mud density = 12.3 ppg
It is required to reduce the hydrostatic pressures in the drillpipe and the annulus so that both
are equal to the formation pressure.
Calculate the volumes of water required in both the annulus and the drillpipe, assuming that
the density of saltwater = 8.65 ppg.
Solution
Annulus Side
Assume the height of water in the annulus to be Y.
Required hydrostatic pressure at stuck point = 5,840 psi or
5,840 = 0.0.52x 8.65x Y + 0.052x 12.3x (11,400-Y)
Y = 7,647 ft (length of water column)
Required volume of water in annulus
= annular capacity between drillpipe and 9.625" casing x height of water
= 0.0515 (bbl/ft) x 7,6476
= 393.8 bbl
Hence, pump 393.8 bbl of water into the annulus to reduce the hydrostatic pressure in the
annulus to 5,840 psi at the stuck point. When 393.8 bbl of water is pumped into the annulus,
the drillpipe is still filled with the original mud of 12.3 ppg having a hydrostatic pressure at
the stuck point of (0.052x12.3 x 11,400) = 7,291 psi. Thus, a back-pressure equivalent to
7,291 – 5840= 1,451 psi will be acting on the annulus and will be attempting to equalise
pressures by back-flowing water from the annulus.

In order to contain the 393.8 bbl of water in the annulus, the drillpipe must also contain a
column of water equal in height to that in the annulus.
Thus,
volume of water required in drillpipe to prevent back-flow from annulus
= capacity of drillpipe x height of water = 0.0178 (bbl/ft) x 7,647 ft = 136 bbl
Balancing of the columns of water in the drillpipe and in the annulus can be achieved as
follows: (a) circulate 393.8 bbl of water down the annulus; (b) circulate 136 bbl of water
down the annulus; (c) circulate 136 bbl of water in the drillpipe to remove 136 bbl of water
from the annulus and to reduce the hydrostatic pressure in the drillpipe to 5,840 psi. At this
stage the hydrostatic pressure in the well is equal to the formation pressure of 5,840 psi.
If the well should kick during the operation, reverse-circulate down the annulus using the
12.3 ppg (i.e. original density) mud to recover all the water from the drillpipe. Then circulate
in the normal way through the drillpipe using 12.3 ppg mud until all the water is removed
from the annulus.