Welcome to
The Chevron
Basic Formation Evaluation
Course
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Formation Evaluation
Formation Evaluation generally thought of as the practice of identifying and quantifying hydrocarbons and reservoir parameters from rock and downhole measurements. Data involved in this practice can come from a wide variety of sources.
wireline logs (open hole, cased hole and production logs) MWD (measurement while drilling)
mudlogs
core and fluid analysis formation testing
Many different types of measurements are made in our attempt to define reservoir properties. These measurements span many types of energy some focus on rock properties other are more sensitive to the fluids. Many have been developed for special logging conditions like oil-based mud. Add to this the fact that logging tools have been around since the 1920s and that there have
historically been 3 to 5 logging companies constantly adding new tools with new capabilities and we end up with a staggering number of tools and measurements all with subtle differences in their interpretation.
The measurements are an almost always-indirect measurement that is to say they do not measure the exact property we are after. Over the years a long list of
equations and techniques have been developed to get from log measurements to reservoir properties. Knowing which ones to choose under what conditions is what sometimes termed the "art" of Formation Evaluation.
It should also be noted that all too often calculations are done with a specific question in mind and that may not be appropriate for all situations. The log
analysis methods may involve many aspects depending on the questions and the time permitted from overlays and quick looks to mineral modeling requiring
computers and detailed understanding of the tools. The techniques employed to answer a simple question are not the same as those required to quantify some reservoir parameter with a high degree of certainty.
1. Will the well produce?
2. If so, will it be oil, gas, or both? 3. Will production include some water? 4. Qualitatively, how much production? 5. What is the depth of the permeable beds? 6. What are the thicknesses of those beds?
7. What is the estimated porosity and saturation of those beds?
Wireline Logging
A wireline log is the product of a survey
operation, also called a survey, consisting of one or more curves. which provides a permanent record of one or more physical measurements as a function of depth in a well bore. Well logs are used to identify and correlate underground rocks, and to determine the mineralogy and physical properties of potential reservoir rocks and the nature of the fluids they contain. In
general a log is the physical paper recording the information, however it has come to also mean digital curves.
1. A well log is recorded during a survey operation in which a sonde is lowered into the well bore by a survey cable. The measurement made by the downhole instrument will be of a physical nature (i.e., electrical, acoustical, nuclear, thermal, dimensional, etc.) pertaining to some part of the wellbore environment or the well bore itself.
2. Other types of well logs are made of data collected at the surface; examples are core logs, drilling-time logs, mud sample logs, hydrocarbon well logs, etc.
3. Still other logs show quantities calculated from other measurements; examples are
movable oil plots, computed logs. etc.
Depth Comtrol
The most fundamental measurement provided by wireline logging contractors is depth. A description of subsurface reservoirs is not of much value if an accurate reference to depth location is not available. Depth control is therefore extremely important to the success of any logging or completion operation.
Contractors specify standards as a function of well depth, wireline cable size, and mud weight. However, in general, all recorded logs are expected to be within to be within a controlled tolerance of 1 ft/10,000 ft (0.3 m/3000 m) of measured depth. Methods for marking the wireline (usually with magnetic marks), knowing the exact distance of the cable makeup to a tool's measure point (including logging head, bridle, etc.), and the distance to the first mark from the downhole end of the cable are all part of the measuring system. In addition, stretch charts for different cable sizes, mud weights, etc. are given for borehole depth, and logging engineers are expected to dedicate themselves to performing depth measurements as
accurately as possible. Wireline log depths are considered the standard for well depth accuracy.
Scales and Reading Logs Today, the presentation of logs varies as a function of the type and number of
services recorded. Tracks represent protions of the log reserved for certain linear or logarithmic scales and grid. Logarithmic scales are generally used for
resistivity data and may occupy one or two tracks. Other log data are generally recorded linearly and may occupy one or two tracks. Track 1 is generally used for control curves (SP, GR, caliper, etx.), but it is also used for quick-look
interpretation information. Porosity-sensitive data such as density, neutron, and acoustic are often recorded linearly across two tracks. Resistivity can occupy one or two tracks but is generally recorded on a logarithmic scale and grid. An
important parameter related to depth is the time marker. To the left of Track 1, a small flag, pip, or gap in the grid is used to indicate time. If calibrated properly, the time marker occurs every 60 sec and can be used to indicate logging speed. This marker is important to log quality control and should be checked periodically for accuracy. Furthermore, a controlled and constant logging speed is important to several log measurements.
Headers
Hole sizes to certain depths are recorded on the driller's log. Driller depths for casing strings already in the well are also recorded. These data should be printed clearly on wireline log headers. It is also common practice for the logging engineer to record the logged depth of casing strings. Log depths should never be intentionally falsified for any reason. If the log is not
recorded to a depth sufficiently shallow to determine the logged casing depth, the designated block on the
header should be left blank. The driller's total well depth should also be recorded. Date and times for each logging run after circulation should also be recorded on the header. Bottomhole temperature should be recorded with maximum reading thermometers on each logging run, and these data should be recorded on the log header.
Other data, such as the surveyed elevations of ground level, derrick floor, sea floor, height above mean sea level, kelly bushing, or similar reference points to depth measurements, should be recorded on the log header. It is important that these data be accurate because the logs can be subpoenaed as legal
documents. These data are also commonly placed on a log tail. The
completeness and accuracy of header information is a fundamental responsibility of the field logging engineer. That engineer's name is also permanently recorded on the header .
The REMARKS section of the log header is used to record any unusual
circumstances observed during the logging operation. This includes reasons for a poor quality log not being rerun, why an SP curve was not recorded, etc. It is the logging engineer's space for explaining any unusual circumstance . Perhaps the properties of the drilling fluid adversely affect the log measurements. If so, it should be mentioned in the REMARKS section. It is also important to record tool series numbers, any additional components, and tool numbers on the header. This information is often a helpful clue to interpretative questions and
troubleshooting tool problems.
Permeability
The ability of fluids to flow through a formation is a key parameter in determining the rate at which any given reservoir will produce fluids. Fluid flow through a formation is governed by three key factors:
1. The nature of the fluid. o this refers to the
thickness or viscosity
of the fluid o more viscous fluids
resist flow and have reduced relative flow rates and vice versa 2. The amount of differential
force exerted on the fluid. o increased pressure differential increases flow rates Note: Neither of these factors are
governed by rock matrix properties, but are determined by reservoir properties.
3. The geometry of the flow paths through the rocks.
o this property is determined by rock matrix properties 4. Rock geometry refers to two separate rock properties.
o physical size and orientation of the rock through which the flow is characterized o physical arrangement of the pore spaces within the rock that the fluid will flow
through
Flow rate is expressed in the following generalized
relationship:
Flow Rate = f(Fluid properties, Differential Pressure, and Rock Geometry)
The mathematical expression for this
relationship is known as Darcy's Law:
q = ( A/ ) x (d /dx) where
q = volume flux (volume per unit time in cc/sec for linear flow) = permeability constant in darcys
A = cross sectional area in cm2 = fluid viscosity in centipoises
d /dx = hydraulic gradient; the difference in pressure, p, in the direction of flow, x, in atm/cm
Permeability is governed by:
1. The size of the flow passages.
o As the size of the flow passages decreases, the permeability of the rock decreases. Generally, permeability decreases as grain size decreases 2. The interconnectivity of the pore spaces.
o As the interconnectivity of the pore spaces is reduced the permeability
decreases; this implies that permeability generally decreases with the an increase in cementation.
3. The tortuosity of the flow paths.
o As the tortuosity of the flow path increases, the permeability decreases, implying that the permeability is generally decreased s the heterogeneity of the sorting increases.
4. The molecular and chemical interaction between the fluid and the rock surface. o As the molecular bonding between the fluid and the rock surface increases, the
permeability decreases.
The permeability of any rock is affected by the attributes of the matrix; the most important characteristics which affect the ease of fluid flow are:
1. Grain size
o As the grain size is decreased, permeability is decreased as a result of a reduction in the effective pore size and the increase in the total surface area per unit volume.
o Increased surface are causes an increase in the amount of fluid bound by chemistry to
the surface; which in turn reduce the amount of pore space available for fluid flow.
2. Packing
o As packing efficiency is increased, permeability is decreased.
o Tortuosity of the flow paths is increased because the packing of the grains results in longer effective pore paths.
o As the uniformity of sorting decreases, the permeability is decreased because of smaller effective flow passages and the increased tortuosity of the flow paths.
Absolute Permeability (k) is the permeability of a rock when fully saturated with a single fluid.
Effective Permeability (ke) is the measure of the permeability of a rock to a
specific fluid at a defined saturation in the presence of another fluid.
Relative Permeability is defined as the ratio between the effective permeability of a rock to a given fluid at a partial saturation and the permeability of that rock at 100% saturations; this is the same as the effective permeability divided by the relative permeability.
Porosity
Porosity is a measurement of the capacity of rock to contain fluids. From the well logging perspective the rock matrix is the solid material, composed of discrete particles or grains, that when lithified, does not consume available space. The small voids that the rock matrix is unable to fill comprise the porosity. That space will be occupied by water, oil, gas, or other liquids.
Porosity is defined as the fraction of the volume not occupied by rock matrix. Mathematically, porosity is expressed by the following equation.
Porosity = Bulk Volume - Matrix Volume / Bulk Volume
Since rock porosity is essentially determined by the ability of matrix particles to fit together, the matrix characteristics of grain size, sorting, cementation, angularity (roundness), and overlying pressure have a great influence on the amount of porosity present in any given rock.
Two fundamental attributes influence porosity: The manner in which the grains are packed The degree to which the grains are sorted Packing The concept of packing is best demonstrated by using the
simplified particle shape of spheroids as seen in the figure below. If a sphere of radius r were placed in a cube with a dimension of 2r, then the porosity of that cube can be accurately computed using the above definition where:
Total volume = (2r)3 and
Matrix Volume = 4/3 r3
Therefore: Porosity =[ 8r3-(4/3) r3] /8r3= 47.6%
If we take a series of these spheroids and pack them in a formation using cubic packing as seen below, the formation would have exactly 47.6% porosity. Additionally, if we were to change the diameter of the sphere, but maintain all spheres of the same diameter with cubic packing, the formation would always have the same porosity.
If the same spheres are now stacked using rhombic packing, the porosity would decrease to 39.5% because the grains fit closer together.
If the grains were packed using rhombohedral packing the porosity would be further reduced to 26%. Parallel cases can be made for non-spherical grain
shape with similar results. Packing affects the efficiency with which grains can fill bulk volume and is a controlling factor in determination of porosity.
Sorting
The concept of sorting can also be demonstrated with the same spherical grain concepts. If we were to take the same cube and grain shown in Figure 1 and add very small diameter spherical grains in the porous space in the corners, the total porosity of the cube would be obviously reduced.
The characteristic of nonuniform sorting has the effect of reducing porosity when all other factors are held constant. Changing grain size when all grains have uniform size has no effect upon the porosity, but increasing the variability of grain size acts to reduce porosity.
Capillary Pressure & Reservoir Quality
The mechanisms controlling the movement and distribution of
immiscible fluids (oil, water, and gas) within a rock, on both the pore and reservoir scales are primarily related to the
properties of the fluids
water must be
displaced. We will find that oil will never succeed in completely displacing the original water within the structure, and where water displacement by oil is the greatest, a residual water saturation will exist which is a function of the rock properties. Furthermore, the amount of oil, which can be recovered economically by primary production and water flooding, varies enormously from less than 10% to more than 80% of the initial oil in place. The distribution and producibility of hydrocarbons can also vary significantly at different levels in the same reservoir.
To understand the processes responsible for these large variations, a basic knowledge of the mechanisms controlling the movement and distribution of fluids (oil, water, and gas) within a rock on both the pore and reservoir scales are required. Contributing factors include the nature of the rock-pore system (the shapes and connectivity of pores and throats, surface area, surface roughness, and electrical charge of the pore walls), the phase behavior and properties of the fluids under reservoir conditions (viscosity, interfacial tension, density, and
wettability), and the forces that cause the fluids to move within the reservoir (gravity, viscous and capillary forces).
Laboratory measurements of capillary pressure, the pressure required to displace a single fluid phase in a multiphase fluid system, provides useful information, which can be related to reservoir conditions to allow us to
understand and predict better the occurrence of hydrocarbons in a reservoir, such as water saturation distributions (initial water saturation, and residual oil saturation), fluid levels (oil / water contact, etc.), and water flood responses.
As permeability and sorting increase, the capillary pressure required to reach irreducible water saturation decreases, and the shape of the capillary pressure curve changes from a lazy curve to a sharp, quick buildup. In the case of the well-sorted, permeable rock, a small increase in capillary pressure results in the filling the volumes connected by large pore-throats (the larger portion of the rock pore volume). A large increase in capillary pressure is required to fill those remaining pore volumes connected by the remaining smaller pore-throats. The net results is a capillary pressure curve with a sharp buildup. For the poorer sorted, less permeable rocks, the pore throats are smaller and, therefore, higher capillary pressures are required to reach a water saturation relative to the well sorted, permeable rocks.
Key Points
1. As sorting and grain size decrease, capillary pressure increase.
2. The shape of a capillary pressure curve is related to permeability and sorting. As K and sorting increase, the transition from 100% water saturation to minimum water saturation is sharper.
3. Capillary pressure curves represent the properties of a single discrete sample. Caution is required when extrapolation to the reservoir scale.
4. Irreducible water saturation (Swi) is the condition where a non-wetting phase cannot
further displace wetting fluid. It is also a measure of the amount of hydrocarbon that can be stored in a pore system.
5. Residual oil saturation (Sor) is a measure of the ultimate amount of hydrocarbon that can
be recovered from a system.
6. Both Swi and Sor can vary dramatically between reservoirs, and their values are critical
endpoints for the evaluation of a reservoir.
7. The shape of a capillary pressure curve is related to permeability and sorting. As K and sorting increase, the transition from 100% water saturation to minimum water saturation is sharper.
8. Capillary pressure curves represent the properties of a single discrete sample. Caution is required when extrapolation to the reservoir scale.
1. Capillary pressure curves can be associated with significant fluid levels in a reservoir: 2. the Free Water Level (FWL) is where capillary pressure is zero.
3. above the FWL both oil and water coexist.
4. the first occurrence of mobile oil is the oil-water contact, (however, other oil-water contact definitions are used).
5. above the critical water saturation level only oil is produced.
6. between the FWL and the irreducible water saturation level is the transition zone.
Resistivity
General Resistivity Principle
The term resistivity (or conductivity) is a general property of materials, as opposed to resistance, which is associated with the geometric form of the
material. The relationship of resistivity to the basic electrical properties of current and voltage are described by Ohm's law:
V = I R
where current I flows through a material with resistance R, and is associated with a voltage drop V. Resistivity R is composed of two parts -- one is material
dependent, and the second is purely geometric (e.g. the length of the sample divided by the surface area of electrical contact plates). From this it follows that
dimensions by which resistivity may be described are Ohm-m/m2 (or, more popularly, Ohm-meters).
As illustrated, a material of resistivity of one Ohm-meter with dimensions of one meter on each side will have a total resistance, face-to-face, of one Ohm. Or, in other words, a one meter cube of formation rock placed between two electrodes of one square meter each defines a resistivity of one Ohm-meter.
Conductivity, the inverse of resistivity (C = 1/R), may be divided into two general types of interest: electrolytic and metallic. Electrolytic conductivity relies on the presence of dissolved salts in a liquid such as water. Metallic conductivity is related to the presence of metals, and is a factor in well logging in ore bodies or, more commonly, with clays or accessory minerals such as pyrite, or graphite. Most rocks are , in essence, insulators and any detectable conductivity usually results from the presence of electrolytic conductors (brine) in the pore space.
The conductivity of rocks is primarily of electrolytic origin. It is the result of the presence of water or a combination of water and hydrocarbons in the he pore space in a continuous phase. The actual conductivity will depend on the
resistivity of the water in the pores and the quantity of water present. To a lesser extent, it will depend on the lithology of the rock matrix, its clay content, and its texture (grain size, and the distribution of pores, clay, and conductive minerals). Finally, conductivity of a sedimentary formation will depend strongly on
temperature (increasing temperature increases electrolytic conductivity). Logging-Related Applications
Determination of water (oil) saturation in the pore spaces of formation rock. Determination of porosity in known water-filled formations.
Stratigraphic correlation of rock sequences between nearby wells.
Characterization of borehole and formation fluids for environmental correction of neutron logs.
Resistivity of Water
As we have seen dry rocks are generally very good insulators. Resistivity is a function of the geometry of water in the rock and the resistivity of that water. When two metal electrodes are connected to a source of
electric current and immersed in a salt solution as in , then an electric potential will exist between the electrodes. The positively charged cations will be attracted to the negatively charged electrode and the negatively charged anions will be attracted to the positively charged
electrode.
The force on each ion will depend on the voltage level and the charge of the ion. The velocity of the ion will depend on the opposition it encounters moving through the solution.
This opposition is determined in turn by the fluid viscosity and the effective size of the ion. The conductivity of a solution has been found to depend on:
1. Charge and size of the ions 2. Ion concentration
The viscosity of water is controlled by the extent of hydrogen bonding between water molecules and consequently, is a strong function of temperature.
Accordingly, the electrical conductivity of aqueous solutions increases sharply with increasing temperature. (The conductivity of metals actually decreases with temperature.)
The above nomograph shows the electrical resistivity as a function of
concentration in parts per million and temperature in degrees Fahrenheit. It is derived from data on NaCl solutions such as that published in the International Critical Tables.
Arps observed that this data can be approximated by the equation listed in . This relationship is easy to use on a calculator. Consequently, the temperature
conversion part of is seldom needed. The charts and equations we have used to convert between salinity and resistivity for different temperatures are applicable strictly only to NaCl solutions. When a brine contains ions other than NaCl, adjustments to these
charts and equations are needed.
The contribution to conductivity of non-NaCl ions can be converted to equivalent amounts of NaCl using multipliers than be more or less than 1. An
this conversion is that the temperature dependence of all ion solutes is the same as that of an NaCl solution of equivalent salinity. This assumption seldom leads to significant errors.
Archie Water Saturation
The resistivitiy of a rock with hydrocarbon and connate water is a function of the amount and distribution of water and hydrocarbon, and the resistivity of the water. The most widely recognized water saturation equation is generally called the "Archie equation". It
is really the result of two empirical relationships observed by G.E. Archie of Shell Oil.
The first is the
relationship between the porosity of a water
saturated sample and it's resistivity.
In the laboratory,
measured the resistivity of numerous specimens having a wide range of porosity values and differing connate water
resistivities. Archie's work concluded that from
a plot of Rw versus Ro plotted data indicate:
1. Any Rw increase causes a corresponding increase in Ro for a given porosity
2. At a given Rw, porosity decreases as Ro increases
3. At any given porosity, the ratio of Ro to Rw is constant, regardless of the Rw value The ratio of rock resistivity (Ro) to connate water resistivity (Rw) is formation factor (F), and F is also a function of porosity. Therefore,
Ro = FRw or F = Ro/Rw
F = a/
ma the intercept generally taken as 1 (but some empirical equations use other values)
m commonly called the cementation exponent generally around 1.8 - 2 for sandstones
The second relationship defines how the resistivity of a rock saturated with water changes as oil as water is replaced by oil.. Oil saturation, (usually expressed as water saturation) is:
Rt/Ro =
S
w-nS
wn= (aR
w)/
mR
twhere:
Rw is the formation water resistivity Rt is the true formation resistivity F is the formation resistivity factor
n is the saturation exponent and lab measurement derived from core usually around 2
Key Points
1. Accuracy of the Archie equation depends on the accuracy of the input parameters; Rw, F and Rt and porosity.
2. This equation is not constrained, values greater than one can be calculated. 3. n can only be measured from core.
4. a and m can be measured from core or back calculated in a wet zone
5. This is the basic water saturation method from resistivity all shaly sand models have this as their basis
Well Log
Analyst View of
Lithology
Lithology has an effect on almost every log reading. The density-neutron log readings are different in a 30% porositydolomite versus a 30% porositysandstone. Once you know the
lithology, you can calculate an accurate porosity
as well as gain an
appreciation for the fluids occupying the pore space in the rock. Knowing the
lithology also makes log interpretation useful for geological interpretation. Wireline log lithology can help a geologist or geophysicist fine-tune a
stratigraphic section, interpret a depositional environment, or validate the mud log.
Log Analyst Rock Classification Model
Geologists separate rocks on the basis of increasing size of the fragments that make up the rock. Usually when litholog descriptions are used by geologists they do not imply any particular mineral composition; i.e., a consolidated beach sand consisting of calcite grains is a sandstone to most geologists.
Log analysts usually subdivide rocks differently than geologist. The primary division for log analysts is between carbonates/evaporites and clastics.
Carbonates include all limestones, dolomites and evaporites. The calcite
"sandstone" of the geologist is a carbonate rock to a log analyst. Clastic rocks, rocks that have been derived by erosion of pre-existing rocks, transported and deposited by water and wind include shales, siltstones, sandstones, and coarser-grained rocks such as grits, cobblestones, or conglomerates. The reason for this terminology is that well logs generally give little information about grain size of rocks coarser than the shale fraction, particularly if they are completely water-saturated. However, lithologies can readily be distinguished by most well logs because of the quite different mineralogy.
Using Log Data to Determine Lithology
Simple lithologic determination can be done with just one curve like the SP or
gamma ray. It can be quite accurate if you already know something about the rock types. If there is more than two rock types present, you need more information than just one curve. More complex lithologic determination can be done with multiple log measurement crossplot techniques (Density/Neutron, Density/Sonic, Neutron/Sonic, MN Plots, or Mid-Plots). Also, the mud log and conventional and sidewall cores can give additional information about the rock type to aid in the wireline log interpretation. There is nothing better than having the rock in your hand.
Logging Tools Measure Bulk Properties
Logs measure bulk properties of the matrix, clays, and pore fluids in the rock. Log readings are affected by variations in
the abundance and type of matrix, clays, and fluids. Determining the matrix lithology requires the formation evaluationist to separate the effects of the fluids on the log readings from those of the porosity. This is possible because different types of measurements respond to different rock properties. The sonic log is sensitive to the acoustic travel time of the rock, the density log is sensitive to the electron density, and the neutron log is sensitive to the hydrogen density.
The petrographer uses the term matrix to describe the minerals present between the framework grains. The formation evaluationist uses the term matrix to
describe the framework grains and uses the term clays to describe the minerals between the matrix grains.
The figure compares the petrograher and Formation Evaluationist view of the term "Matrix" and the bulk properties measured by logging measurements.
Clays and Shales
The term "clay" can have several different meanings. One meaning is a grain size term, any thing less than two microns in size. As it relates to formation evaluation clays are a family of sheet silicate minerals that are found in many sedimentary environments. There are many clay minerals but they are typically classified into 4 main groups; kaolinite, chlorites, illites and smectites. Clays have some very unique properties which effect responses on wireline logs and
therefore make their quantification extremely important.
Clay surface areas (often expressed as CEC) are typically six to seven orders of magnitude greater than that of sandstone grains. This becomes important for two reasons:
1. the number of possible reaction sites available in the pore space increases, resulting in an increase in matrix conductivity.
2. the amount of water that can be held by capillary forces in the additional micropore space is increased; since this water is immobile, it is not produced, however, it will show up on logs complicating the decision-making process.
Clays vs. Shales
One of the most confused set of terms in formation evaluation is clay and shale. We often use these terms interchangeably and cause much confusion. Shale is a rock term referring to a sedimentary rock with > 60% clays sized particles usually but exclusively clay minerals. Most shales are made up of 55 to 90% clay
minerals with remained being quartz, feldspar, rock fragments and some organic material. Many log evaluation techniques try to account for clay effects without having any direct information about the clay minerals so these techniques use the shale properties (something that is measured on the log)as a first
measurements but they are an attempt to account for the adverse affects of clays.
Over 80% of all sedimentary rocks are shales, with the remainder being about 60% sandstone and 40% carbonate. Clay minerals, including the several
varieties of mica, usually make up about 60% of shales, with the remainder being mostly fine-grained fragments of those minerals occurring in sandstones that best survive weathering.The fractions of the common clay minerals range greatly for shales of different geological ages. Clay mineralogy is related to depositional history, diagenetic processes, depth of burial, rock age and other factors. Older shales show increasing amounts of illite, and less smectite and other expanded clays.
Detrital vs Authigenic
Clay minerals are almost always a significant part of any clastic depositional system. So clays can be laid down with sand grains usually as alternating sand and shale sequences or more mixed if the or bioturbated . Once
deposited mineralogy can continue to change dewatering chemical substitution
Key Points
1. Shales are not made up of exclusively of clay minerals
2. The clays in sands may not be the same as the clays in the shales 3. Different clays have varying effects on log measurements
4. For some log measurements the distribution of clay is as important as the type of clay mineral
5. Chlorite and Kaolinte have higher OH content and therefore stronger effect the thermal neutron
6. Illite is the only clay mineral with strong radioactive component 7. All have OH- in the crystal structure
Evalution of Sandstones Reservoirs
The primary formation evaluation objectives in both carbonate and clastic rocks are similar, for example, the identification, quantification, and producibility of hydrocarbons. Problems related to formation evaluation of sandstones are varied and numerous; clay effects on logs, evaluation in fresh water reservoirs, and evaluation problems caused during the drilling of the well. Sandstones range from massive, clean, well-sorted and unconsolidated to thin-bedded, shaly and/or calcareous, poorly sorted and well indurated. Reservoir characteristics for
productive sands can have an equally wide range. Characterization of Sandstone Reservoirs
Sandstones range from massive, clean, well-sorted and unconsolidated to thin-bedded, shaly and/or calcareous, poorly sorted and well indurated. Reservoir characteristics for productive sands can have an equally wide range.
The average porosity of sandstone reservoirs is perhaps double the average porosity for carbonate reservoirs. In some prolific carbonate producing provinces, maximum average reservoir porosity is less than ten percent.
Typically, sandstone reservoirs with low porosity do not have enough
permeability for commercial production of anything but gas (unless they are fractured).
Sandstones typically have narrow permeability ranges. Sandstone permeabilities up to several darcies are not uncommon. The exception are thin-bedded
Evaluation Problems in Sandstone Reservoirs
1. Sandstones are usually deposited initially in muddy water, and always contain some fine material that includes clay minerals. Some sandstones have been winnowed by currents or winds, and most (but never all) of the fine fraction containing the clay minerals has been removed. Other sandstones have been dumped with very little sorting by the geological processes that deposited them so that they have a wide range of grain sizes, often including up to 30% or more clay-size material.
2. Sandstone interpretation problems caused by clays are often aggravated by the presence of fresh formation waters. Very fresh formation waters are almost unknown in producing carbonate reservoirs, whereas productive sandstone with reservoirs water salinities of less than 5000 ppm are not uncommon.
3. When holes are drilled in harder consolidated rocks, they remain close to the drilled diameter due to the more competent nature of the rocks. Drill cuttings are usually representative of the rocks being drilled. Conventional core can be used, but sidewall coring is less successful. Packer seats can be obtained, permitting drillstem testing when porosity is encountered. Much of the evaluation is accomplished during drilling and before logs are run. In contrast to that; in soft, unconsolidated sandstone have poor hole conditions that limits evaluation during drilling. Wells are evaluated mostly at total depth using wireline logs, plus hydrocarbon logs and sidewall samples. Conventional coring is often unsuccessful. However, a plastic sleeve core barrel may not only improve recovery, but also minimize trauma to the core during handling. Open hole drillstem tests are often unsafe, and packer seats are commonly unobtainable. Wireline formation tests are used to determine reservoir fluid content and pressures. Often they are inconclusive because of bad hole conditions or deep invasion. If a potential productive zone is found by these methods, it is tested by completing the well and production testing.
Clastics and Carbonates have different reservoir properties and the log analyst uses different formation evaluation methods.
Comparison of Carbonate and Sandstone
Reservoir Parameters
Sandstones 10% 38% 10 Darcies Always Common Parameter Minimum Porosity Maximum Porosity Maximum Permeability Conductive Solids Fresh Formation WaterCarbonates 2% 50% >> 10 Darcies Rare Rare
1. Formation evaluation and drilling problems associated with sandstone reservoirs, and the methods developed to solve them, can be quite different from those related to carbonate rocks.
2. Sandstones range from massive, clean, well-sorted and unconsolidated to thin-bedded, shaly and/or calcareous, poorly sorted and well indurated. Reservoir characteristics for productive sands can have an equally wide range.
3. Problems related to formation evaluation of these sandstones are varied and numerous; some are similar to carbonate problems, while others are unique to sandstones. The average porosity of sandstone reservoirs is perhaps double the average porosity for carbonate reservoirs. In some prolific carbonate producing provinces, maximum average reservoir porosity is less than ten percent.
4. Typically, sandstone reservoirs with such low porosity do not have enough permeability for commercial production of anything but gas (unless they are fractured). On the other hand, some chalk carbonate reservoirs have porosity greater than any found in
sandstones.
5. Sandstones typically have narrower permeability ranges than carbonates. Sandstone permeabilities up to several darcies are not uncommon, but nothing comparable to the huge permeabilities of coarsely vugular and cavernous carbonates are found in clastic rocks.
6. Problems unique to sandstone reservoirs are mostly due to two factors:
Sandstones are usually deposited initially in muddy water, and always contain some fine material that includes clay minerals.
7. Carbonate reservoir rocks are almost always deposited in very clear water, because this is the environment most favorable to the living organisms that create the minerals. 8. Some sandstones have been winnowed by currents or winds, and most (but never all) of
9. Other sandstones have been dumped with very little sorting by the geological processes that deposited them; resulting in a wide range of grain sizes, often including up to 30% or more clay-size material.
10. Sandstone interpretation problems caused by clays are often aggravated by the presence of fresh formation waters.Very fresh formation waters are almost unknown in producing carbonate reservoirs.Productive sandstone reservoirs with water salinities of less than 5000 ppm are not uncommon.
Evaluation Methods Comparison
Carbonates vs. Sandstones
Formation EvaluationMethod Value in Sandstones Value in Carbonates
Wireline Logs Not always diagnostic Usually reliable Mud Logging Essential Very Useful Conventional Cores Poor recovery Widely Used Plastic Sleeve Cores Valuable Rarely Used Sidewall Cores Essential Some Use Wireline Tester Essential Widely Used Drillstem Testing Difficult and Dangerous Widely Used Testing Through Casing Often Necessary Occasionally Required 'Shaly Sand' Interpretation
Problems Common Rare
Borehole Terminology
An idealized borehole is a cylinder of uniform diameter filled with a drilling mud
"ideal" for logging conditions. Most wireline tools developed for openhole formation evaluation have been optimized to operate in 8" borehole.
As the drill bit
penetrates geological horizons in the
subsurface, drilling fluid is introduced to that formation for the first time. Mud
pressure, penetration rate, and the porous, permeable nature of the rock being penetrated are variables largely responsible for the eventual profile of invasion. In general, wells are drilled with pressure slightly overbalanced to contain reservoir pore pressure and avoid potential blowouts. Impermeable rocks do not experience invasion; however,
low-porosity rocks with some permeability are often invaded deeply because available pore spaces to accept the penetrating fluids are widely spread around the borehole. Rock with high porosity and high permeability normally
demonstrates shallow invasion because there is more pore volume near the borehole to accept invading fluids.
Logging Terminology in the Borehole
Standard terminology is used to refers to the resistivites and saturations of these regions as shown.
The flushed zone immediately adjacent to the borehole is at most, a few inches (centimeters) beyond the borehole wall and essentially contains only mud filtrate (Rmf) as occupying fluid . The flushed zone has unique resistivity (Rxo) and
saturation (Sxo) values. Most native fluids and gases are flushed farther into the
formation, and those that remain are called residual or immovable. Oil reservoirs typically demonstrate residual oil saturations of 15% to 40%, but trapped residual waters are not uncommon, especially in carbonate reservoirs. As time passes, some of the mud filtrate continues to migrate laterally into the formation; i.e., it begins to commingle with native reservoir fluids and form a transition zone between the flushed zone and undisturbed reservoir rock . Water saturation in this transition zone (Si) can vary considerably if the reservoir contains
hydrocarbons. A water-bearing horizon will continue to exhibit 100% water
saturation, but the commingled waters have differing salinities or resistivities (Rz).
The resistivity of the invaded zone (Ri) will therefore differ from that of the flushed
zone and virgin zone beyond. The length of time the formation is exposed to the borehole fluid pressures influences the depth of invasion, but permeability and porosity also influence the lateral distance of invasion. A hypothetical view of the diameter of invasion in formations that are somewhat heterogeneous illustrates the effects of porosity and permeability. Diameter of invasion (di) represents the
lateral interval encompassing the borehole that is affected by invading drilling fluid, whereas the diameter of flushing (dxo) is much smaller. The virgin reservoir
rock has a resistivity (Ro) if it is 100% water bearing, but if the formation contains
any hydrocarbon, it has a higher value of resistivity (Rt). The native connate
water saturation (Sw); i.e., Sw decreases as the volume of oil or gas increases.
Resistivity increases as nonconductive hydrocarbon replaces conductive formation waters in the pore space.
Geothermal Gradient
Temperatures at depth can be estimated by using the geothermal gradient if one knows the mean surface temperature and the geothermal gradient. Subsurface temperatures normally increases with depth, and the rate of increase with depth is called the geothermal
gradient, defined as: GG = 100(Tf-Tm)D where GG = geothermal gradient (°F/100 ft), Tf = formation temperature (°F), Tm = mean surface
temperature for a given area (°F), D = depth of formation of interest (ft).
This equation can also be written as: Tf = Tm + GG(D/100)
and allows an estimate of formation temperature. Charts are available to estimate formation temperatures using a geothermal gradient as shown below:
Mean surface temperature data are usually provided by governmental agencies. In many countries, maps for different seasons are available. Obviously, extreme cold at the surface will affect temperature at very shallow depths (< 1,000 ft), but extreme heat at the surface will also affect the temperature gradient in very shallow wells.
Thermal Conductivity of Rocks (10-3 calories/cm/°C)
Shale 2.8-5.6 Gypsum 3.1 Water 12-14 Sandstone 3.5-7.7 Anhydrite 13 Air 0.06 Porous Limestone 4-7 Salt 12.75 Oil 0.35 Dense Limestone 6-8 Sulphur 0.6 Gas 0.065 Dolomite 9-13 Steel 110 Quartzite 13 Cement 0.7
The geothermal gradient is a function of the thermal conductivity of the rocks in the subsurface (see table below). A chart with several gradients is provided for estimating temperature (see chart above), but recall that gradients are seldom
constant. Temperature surveys have been used effectively to identify different lithology layers from
temperature gradient changes (see figure below). Certain geological structures, such as salt domes or
reefs, overpressured zones, and different geological ages are factors that cause changes in the geothermal gradient. In one area of the Rocky Mountains (USA), the gradient increases from 1.1 to 1.4 when going into
Paleozoic rocks from the younger rocks above.
Key Points
1. Formation temperature and heat conductivity
are important to formation evaluation because all resistivity data are temperature dependent. 2. Geothermal gradient is a function of the
thermal conductivity of the rocks in the subsurface
3. Geothermal gradients are seldom constant. 4. Extreme cold at the surface will affect
temperature at very shallow depths (< 1,000 ft).
5. Extreme heat at the surface will affect the temperature gradient in very shallow wells.
6. Temperature surveys have been used effectively to identify different lithology layers from temperature gradient changes.
o salt domes or reefs o overpressured zones o different geological ages
7. Thermal conductivity of water does not change appreciably with increasing salt concentration.
8. The effects of pore fluids on gross conductivity is relatively small for rocks of low to moderate porosity.
9. Thermal conductivity of clays tends to vary inversely with the water content.
o In overpressured zones, the higher pore pressure causes higher porosity that accounts for more fluid volume.
o Geothermal gradients are typically larger in massive shale formations that overlay reservoir rocks.
o Geothermal gradients are usually reduced considerably in aquifers. o Overpressured, high-porosity shales represent a geothermal anomaly.
Temperatures in a Drilling Borehole
The process of circulating drilling fluids (mud) creates a very complex temperature distribution along the borehole - deep zones are cooled while shallow zones are heated.
Geothermal measurements are made in boreholes which have temperature-depth profiles different from the geothermal profile. This is largely due to heat
transfer caused by fluid flow (e.g., circulation of drilling mud, upward flow of produced reservoir fluids, downward flow of injection fluids) as seen from the
Tempertures in a static well
During the period of time required to pull pipe (drill pipe) and start logging, the annular (annulus)and drill pipe fluids (mud) mix and heat transfer continues between the borehole and formation. The borehole temperature profile changes from that shown previously and becomes fairly linear with depth, except near total depth, as shown in figure below. At point X, the borehole temperature is equal to the formation temperature and no heat transfer
occurs. With the passage of additional time, the borehole fluid (mud) cools above point X and warms below point X as both borehole regions approach thermal equilibrium with the formation.
Formation Temperatures from Logs
We can estimate true formationtemperature by making temperature readings on each tool run. We then extrapolate, using a technique similar to the Horner plot used in pressure prediction.
Although continuous temperature measuring devices are readily available, most
borehole temperature estimates are made from maximum-reading thermometers
attached above wireline logging tools. Except in areas such as steam drives, where the normal geothermal gradient is disrupted, this maximum temperature reading is assumed to coincide with the bottom of the hole.
The cooling effect of circulating drilling mud on formations prior to logging can reduce measured bottom hole temperature from thermometer readings by 20°F to 80°F below actual formation temperature. Thus, the BHT recorded on the log header is always lower than true, or static, formation temperature.
Since the rise in temperature is similar to a rise in pressure, Timko and Fertl (1972) suggested that BHT data can be analyzed in a manner similar to the Horner pressure-buildup technique. The basic concept predicts a straight-line relationship on semilogarithmic paper of BHT in °F (from well log heading) vs the ratio of t/(t + t), where t= time in hours after circulation stopped; t = circulating time in hours for well conditioning. Extrapolation of this straight line to a ratio of t/(t + t)= 1.0 determines true static formation temperature as shown in the figure below.
Borehole Cross Sections
Boreholecross sections are measured to assure that logging measurements are valid, to correct logging measurements
calibrations for downhole
conditions, and to compute hole volumes for cement design.
Borehole size or gauge has been measured with caliper logs for many years. The caliper logs used on different tools respond differently in the same non-cylindrical borehole.
Borehole cross sections are often described as circles and ellipses because only these shapes can be defined from the one or two dimensions usually available from one logging run. Studies of multi-arm calipers indicate that borehole
elongation is preferentially in one direction while the section at right angles tends to stay in gauge. The borehole also tends to be more rugose in the direction of maximum elongation.
Standard Caliper Log Configurations
1. One arm calipers also serves as an eccentering device.
o Tend to seek the longest dimension of the borehole cross section, especially if the long axis is in a vertical plane. o If the contact with borehole is steel it is considered to cut
through mudcakes. If the contact is rubber, it reads borehole minus one mudcake thickness.
2. Two arm calipers, extend equidistant from a centralized tool body.
o Tend to record the long axis of out-of-round holes.
o All borehole contacts are rubber and measurement is considered as borehole minus two mudcake thickness.
3. Three arm calipers, center the tool body.
o Maintain their arms equidistant from the body of the tool and measure only one diameter,somewhere between the minimum and maximum of the noncircular section.
4. Four arm calipers, consisting of two calipers at right angles to each other. o Four-arm calipers typically use two pairs of arms that extend
independently of each other. One pair seeks the long dimension of an out of round hole, the other measures the dimension at right angles.
5. Six-arm devices, which use six independent arms, spaced at 60o angles, allowing the characterization of irregular shaped boreholes.
o Six-arm calipers have each arm independent, allowing the arms to characterize the hole shape regardless of the relative position of the tool body. An advantage to this design is that significant pressure is not required to make a measurement, thereby reducing tool drag and irregular tool motion.
Tool Contact
In addition to the number of arms, the nature of the tool contact also affects the caliper response when a hole is not cylindrical or has mudcake. Devices that have small contact area can detect smaller borehole irregularities. Contact pressure is usually high enough to cut through any mudcake (steel pads). Pad type devices have somewhat larger pad contact area and when operated at lower contact pressures will override mudcake (rubber pads).
Changes in hole shape may not be sensed if the borehole irregularities are changing rapidly and are smaller than the pad dimensions, depending on how the tool contacts the borehole wall.
Invasion
Drilling muds are typically designed so the hydrostatic pressure of the mud column exceeds formation pressure. This pressure overbalance causes mud to
enter permeable formations while at the same time depositing solid particles from the mud system on the borehole wall, forming a filter cake (hmc). The time
required to build up sufficient mudcake is a function of specific formation properties and drilling fluid properties, especially solid particles within the mud system. Formation of the filter cake prevents further filtrate invasion and formation damage while maintaining wellbore stability.
In most mud systems, invasion is expected. These invading mud particles alter formation composition, and invading mud filtrate alters formation salinity and saturation. As a result of this invasion, some logging measurements reflect drilling altered properties rather than true formation properties. Separating the part of the logging
response that comes from the invasion altered
region from the part derived from unaltered formation is a major task in well log interpretation. The control of the mud surge and particle migration is primarily dependent on two things:
1. Maintaining a good size distribution of solid particles in the mud
2. Keeping the drilling fluid-formation pressure overbalance as low as possible.
The porosity of a formation needs to be considered in predicting invasion depth. Given the same filtrate losses into equally thick intervals:
Invasion will be deeper in the formation with a lower porosity; high filtration and low porosity cause "deep invasion".
For most realistic conditions, invasion cannot be eliminated, only slowed. So, prospective intervals should be evaluated as soon as possible.
The depth of investigation of a logging tool determines how much the measurement is affected by invasion. Evaluation of water saturation from electrical properties requires an accurate determination of uninvaded formation resistivity or conductivity. Ideally, a deep sensing resistivity (or conductivity) log (RLD) is designed to respond to unaltered formation resistivity (Rt) without being
influenced by any of the following:
Mud column (Rm)
Mudcake (Rmc)
Mud impregnated zone (Rim)
Flushed zone (Rxo); immediately adjacent to the borehole wall and essentially contains
only mud filtrate (Rmf)
Transition zone (Ri) Annulus (Ran) Invasion Profiles 1. Step 2. Transition 3. Annular Affects of Invasion on Water Saturation Calculations If invasion is extensive and the deep resistivity log (RLD) is responding
partially to an invasion altered region; without invasion corrections, Sw
calculations are affected as follows;
Hydrocarbon saturation
will be overestimated when Rxo > Rt
Hydrocarbon saturation may be underestimated if RLD is significantly affected by a low resistivity annulus.
Some formations may be so deeply invaded that saturation evaluation is not possible
Corrections for invasion and determination of depth of invasion require an accurate flushed zone resistivity for even the simplest cases. For more complex and deep alterations, additional measurements with intermediate depths of investigation are required.
Key Points
The pressure overbalance in the borehole causes mud and mud filtrate to "invade" the borehole wall.
Mud cake slows fluid and solid invasion into the formation; some muds contain material which affects log readings.
Mudcake is formed from the solids in the drilling mud.
Ideally mudcake should form quickly and have low permeability to reduce invasion. Deeper invasion occurs in lower porosity.
Prospective intervals should be evaluated as soon as possible after drilling.
The depth of investigation of a logging tool determines how much the measurement is affected by invasion.
Spontaneous Potential The Spontaneous Potential, commonly abbreviated SP, is a measurement of the naturally occurring electrical potentials in the wellbore as a function of depth. It is one of the oldest logging
measurements and in today's environment one of the most under utilized measurements. It is sensitive to grain size, permeability and fluid content. SP is somewhat less quantitative than other
Basic Measurement Principles
The recording of the SP is the measured potential difference between a single passive moving electrode in the wellbore and a reference electrode, usually located at the surface in the mud pit, or attached to the casing head, or in sea water. There are three possible sources of the electrical potential which contribute to the SP; they are:
1. The electrochemical, Ec potential ,made up of the.membrane and liquid junction
potentials
2. The electrokinetic, Ek. potential. (sometimes called streaming potential)
The sum of these different potentials results in a measurement that is not absolute but relative. The potential sensed by the SP electrode is the voltage drop across the mud in the borehole and is typically reported in mv. Since the SP requires a current path in the mud it will not function in an oil based mud. There also be little or no signal if there is no potential difference between the borehole and the formation i.e. where Rmf=Rw.
The maximum normally encountered SP is called the static SP (SSP). The SSP is the amount of deflection observed when the SP electrode passes from a position inside a very thick, porous, permeable, clean water sand to a point well within a thick uniform shale. The SSP is the value of the SP that is predicted by the following equation: SP = -Klog (aw/amf) ; where:
aw = the activity of the formation water amf = is the activity of the mud filtrate K = constant
Several factors can contribute to less than maximum deflection
1. Insufficient bed thickness causes the effective resistance of the sand to increase because of the corresponding reduction in the cross sectional area of the sand.
2. Increased borehole diameter, the effective resistance of the mud decreases because of the increase of the cross sectional area of the borehole.
3. Deep invasion the interface between the liquid junction and the membrane junction is moved deeper into the formation; which increases the effective resistance of the sand because of the increased path length to the borehole.
4. Presence of hydrocarbons increases the effective resistance of the sand because oil and/or gas have a much higher resistivity than water resulting in a greater drop of potential across the sand, resulting in a suppression of the SP deflection
5. Presence of clay restricts the migration of Cl- ions and assists the migration of Na+ ions due to the predominant negative charge of the clay
6. Significantly reduced porosity and permeability
The shape of the SP curve approaching or leaving the sand/shale boundary is controlled by the relative resistivities of the mud, sand, and shale, an inflection point is observed at the bed boundary interface. This inflection point may be shifted to closure to one formation or another depending on relative resistivities but the inflection point represents the bed boundary.
Applications
differentiate permeable from non-permeable formations determine bed boundaries and bed thickness
determine formation water resistivity, Rw
can be used to calculate Rw in wet zones estimate the volume of shale, Vsh
Borehole and Quality Considerations
1. SP's are very sensitive to extraneous electrical fields which can be caused by welding or other rig electrical equipment, residual magnetism from the cable drum, or atmospheric electrical charges.
2. Unresponsive SP's can be caused by poor grounding of the surface electrode
3. Streaming potentials can caused by under or overbalanced mud columns with differential pressure into or out of the formation.
4. The SP is a relative measurement and drifts with salinity and temperature changes, practice in older logs was for the field engineer to manually bring the SP back on scale. These scale changes are generally obvious but may confuse interpretation.
5. Hydrocarbon causes suppression of the SP signal
6. Thin beds affect SP development how much depends on the resistivity of the formation and the contrast between Rw and Rmf
7. SPs are often base adjusted to remove shifts and drift this needs to be done carefully so as not to introduce anomalous readings
Key Points
1. Variations in SP are the result of the electric potential between the wellbore and the formation as result of the difference is the Rmf and Rw
2. In most wellbore environments, where salinity of the formation water is greater than the salinity of the mud or mud filtrate(Rw<Rmf). The result of this relationship is that the
expected SP development opposite relatively high salinity formations is negative. The deflection will be positive if Rw>Rmf.
3. The SP requires a conductive fluid in the borehole, therefore cannot the SP can not be run in non-conductive mud systems or air or gas drilled wells.
4. The SP response of shales is relatively constant and follows a straight line, known as the shale baseline. SP deflection is measured from the shale baseline.
5. If Rmf Rw the SP will not deflect from the shale baseline.
Gamma Ray Log
The gamma ray log is probably the most widely run logging measurement. It is used to distinguish lithologies particularly sand from shale. It is a relatively simple measurement and works in open hole or cased so it is the primary measurement for deep control and correlation.
Measurement Principles
Gamma Rays are bursts of high energy electromagnetic waves which are emitted spontaneously by some radioactive elements. Nearly all of the gamma radiation encountered in the earth is emitted by the radioactive potassium isotope of atomic weight 40 and the radioactive elements of the uranium and thorium
series. For the most part these elements are found in minerals and solid organic material so almost all the signal comes from the rock matrix and not from the fluid.(some exceptions do occur, usually tracers or radioactive salts added to muds)
The gamma ray log is a passive measurement. Gamma rays from the logging environment strike the detector either a solid state crystal (NaI or CsI), or a Geiger Mueller gas chamber and the incident gamma rays produce a signal which is recorded as counts/second. The counts are converted to API units, a standard defined for gamma ray logs and units used to display this
measurement. The higher the API the more gamma ray counts recorded. Gamma rays are only slightly attenuated by mud , casing and cement so the measurement can be made under most open and cased hole situations. Applications
1. To distinguish shale beds from other lithologies
2. Semi quantitative calculation the volume of shale and/or clay in reservoir rocks; this assumes the clean zones do not contain radioactive minerals, i.e., granite wash, micaceous sands, radioactive carbonates.
o Vsh = (Grzone- Grclean)/(Grshale- Grclean)
o Other nonlinear equations are used in some areas
3. Correlation and depth control log, between wells and for logging runs in the same well 4. ID zones of fluid flow (often leaves radioactive scale),fractures, and radioactive tracers
Borehole and Quality Considerations
1. Hole Size
o increased borehole diameter attenuates the detector response by moving the tool farther from the formation
2. Position of the tool in the borehole, eccentered tools are closer to the borehole wall 3. Variations in the mud system
o bentonite, a clay mineral, is used widely as a gel additive and contains significant amounts of Th an U.
o Potassium salts (KCL) are frequently used for clay stabilization
o Barite weighting material tends to shield the detectors from the formation by increasing the photoelectric absorption of gamma rays
4. Variations in casing size and weight
o Casing properties such as, thickness, material, grade and its position in the hole, as well as the cement properties introduce variations in the energy spectra. 5. Variations in porosity can have effect more rock material means more counts
Key Points
1. Gamma Ray logs are lithology logs that measure the natural radioactivity of a formation 2. Because radioactive material is concentrated in shale, shale has high gamma ray
readings and generally sands and carbonates have low gamma ray readings; exceptions are granite wash, micaceous sands, and radioactive carbonates.
3. The gamma ray provides bed information in those environments where the SP is not diagnostic, i.e., salt muds, oil based muds, air or gas drilled holes, and cased holes. 4. Vertical resolution is affected by logging speed, but is approximately 2' at a logging
speed of 1800 feet/hr.
5. The gamma ray is a statistical measurement not every wiggle on the curve is significant. In general the tools that are run the slowest give the better readings.
6. Depth of investigation of the gamma ray is approximately 10 - 12 ".
7. The gamma ray log is nearly always recorded in track 1 of the log display. It is scaled so that low radioactivity is near the left side of the track and increases to the right toward the depth column.
Acoustic Logging
Acoustic logging uses various forms of sound wave propagation. The acoustic logging principle is related to seismic exploration methods, since both derive data from wave travel times. Types of acoustic measurements include:
Measurement of compressional wave travel times for porosity determination.
Recording of full waveforms for differentiating compressional, shear, and Stoneley (Tube) wave travel times.
Characterization of the borehole environment (cement evaluation or televiewer imaging of the borehole wall).
Integration (summation) of interval transit times as an aid to interpretation of seismic data.
The basic acoustic log is a recording, versus depth, of the time, t (delta-t), required for a compressional sound wave to traverse one foot of formation. Known as interval transit time, t is the reciprocal of compressional wave velocity, and is usually expressed in terms of micro-seconds per foot. The interval transit time for a given formation depends on its lithology and porosity. Dependence on porosity, when lithology is known, makes the acoustic log very useful in formation evaluation.
Measurement Principle The most commonly used borehole compensated acoustic logs use receivers positioned three feet and five feet from each
transmitter. Long-spaced
tools are sometimes used having transmitter-receiver spacings of 10 feet or more. When one of the transmitters is pulsed, a sound wave is generated and travels through the borehole fluid to the borehole wall, where it is refractedalong the wall, reflected back across the fluid column to two receivers, and recorded as the elapsed time required for the first compressional wave arrival. The difference in the travel (arrival) times between the two receivers, which are a known
distance apart, represents the acoustic velocity through the formation. This is known as acoustic interval transit time (t), the time interval representative of the distance between the two receivers expressed in micro-seconds per foot. Each rock type has a characteristic acoustic velocity. Voids in the rock slow the transit time, allowing porosity to be calculated.
A knowledge of lithology and fluid type allows porosity to be calculated by empirical means. The speed of sound through the tool body and through the borehole fluid is less than that in the formation. As a result, direct tool body and fluid waves do not interfere with the desired measurement. A knowledge of fluid travel time and lithology is needed to calculate porosity.
