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